SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K (Mark One)

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2002

OR

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission file number 1-9356

Buckeye Partners, L.P. (Exact name of registrant as specified in its charter)

Delaware 23-2432497 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification number)

5002 Buckeye Road P. O. Box 368 Emmaus, Pennsylvania 18049 (Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (484) 232-4000

Securities registered pursuant to Section 12(b) of the Act: Title of each class

Name of each exchange on which registered

LP Units representing limited partnership interests........................................... New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None (Title of class)

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act 12b-2). Yes No At June 28, 2002, the aggregate market value of the registrant’s LP Units held by non-affiliates was $888 million. The calculation of such market value should not be construed as an admission or conclusion by the registrant that any person is in fact an affiliate of the registrant.

LP Units outstanding as of March 13, 2003: 28,702,346

TABLE OF CONTENTS

Page

PART I Item 1. Business .................................................................................................................................... 3Item 2. Properties.................................................................................................................................. 13Item 3. Legal Proceedings .................................................................................................................... 13Item 4. Submission of Matters to a Vote of Security Holders ............................................................. 14 PART II Item 5. Market for the Registrant’s LP Units and Related Unitholder Matters ................................. 14Item 6. Selected Financial Data .......................................................................................................... 15Item 7. Management’s Discussion and Analysis of Financial Condition and

Results of Operations ............................................................................................................. 16Item 7A. Quantitative and Qualitative Disclosures About Market Risk ................................................ 26Item 8. Financial Statements and Supplementary Data...................................................................... 28Item 9. Changes in and Disagreements with Accountants on Accounting and

Financial Disclosure ................................................................................................................ 53 PART III Item 10. Directors and Executive Officers of the Registrant ................................................................ 54Item 11. Executive Compensation ......................................................................................................... 56Item 12. Security Ownership of Certain Beneficial Owners and Management ................................... 57Item 13. Certain Relationships and Related Transactions .................................................................... 59Item 14. Controls & Procedures............................................................................................................. 60 PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K .................................... 61

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PART I

Item 1. Business Introduction Buckeye Partners, L.P. (the “Partnership”), the Registrant, is a master limited partnership organized in 1986 under the laws of the state of Delaware. The Partnership’s principal line of business is the transportation, terminalling and storage of refined petroleum products for major integrated oil companies, large refined product marketing companies and major end users of petroleum products on a fee basis through facilities owned and operated by the Partnership. The Partnership also operates pipelines owned by third parties under contracts with major integrated oil and chemical companies. The Partnership conducts all its operations through subsidiary entities. These operating subsidiaries are Buckeye Pipe Line Company, L.P. (“Buckeye”), Laurel Pipe Line Company, L.P. (“Laurel”), Everglades Pipe Line Company, L.P. (“Everglades”) and Buckeye Pipe Line Holdings, L.P. (“BPH”). (Each of Buckeye, Laurel, Everglades and BPH is referred to individually as an “Operating Partnership” and collectively as the “Operating Partnerships”). The Partnership owns approximately a 99 percent interest in each of the Operating Partnerships. BPH owns directly, or indirectly, a 100 percent interest in each of Buckeye Terminals, LLC (“BT”), Norco Pipe Line Company, LLC (“Norco”) and Buckeye Gulf Coast Pipe Lines, L.P. (“BGC”). BPH also owns a 75 percent interest in WesPac Pipeline-Reno Ltd., WesPac Pipeline-San Diego, Ltd. and related WesPac entities (collectively known as “WesPac”) and an 18.52 percent interest in West Shore Pipe Line Company. Buckeye Pipe Line Company (the “General Partner”) serves as the general partner to the Partnership. As of December 31, 2002, the General Partner owned approximately a 1 percent general partnership interest in the Partnership and approximately a 1 percent general partnership interest in each Operating Partnership, for an effective 2 percent interest in the Partnership. The General Partner is a wholly-owned subsidiary of Buckeye Management Company (“BMC”). BMC is a wholly-owned subsidiary of Glenmoor, Ltd. (“Glenmoor”). Glenmoor is owned by certain directors and members of senior management of the General Partner and trusts for the benefit of their families and by certain other management employees of Buckeye Pipe Line Services Company (“Services Company”). Services Company employs a significant portion of the employees that work for the Operating Partnerships. At December 31, 2002, Services Company had 506 full-time employees. Services Company entered into a Services Agreement with BMC and the General Partner in August 1997 to provide services to the Partnership and the Operating Partnerships through March 2011. Services Company is reimbursed by BMC or the General Partner for its direct and indirect expenses, which in turn are reimbursed by the Partnership, except for certain executive compensation costs. BT, Norco and BGC directly employed 115 full-time employees at December 31, 2002. Buckeye is one of the largest independent pipeline common carriers of refined petroleum products in the United States, with 2,909 miles of pipeline serving 9 states. Laurel owns a 345-mile common carrier refined products pipeline located principally in Pennsylvania. Norco owns a 482-mile pipeline in Indiana, Illinois and Ohio. Everglades owns 37 miles of refined petroleum products pipeline in Florida. Buckeye, Laurel, Norco and Everglades conduct the Partnership’s refined products pipeline business. BPH, through facilities it owns in Taylor, Michigan, provides bulk storage service with an aggregate capacity of 260,000 barrels of refined petroleum products. BT, with facilities located in New York, Pennsylvania, Ohio, Indiana and Illinois provides bulk storage services with an aggregate capacity of 4,848,000 barrels of refined petroleum products. BGC owns and operates petrochemical pipelines in the Gulf Coast area. BGC also provides engineering and construction management services to major chemical companies in the Gulf Coast area. WesPac provides turbine fuel transportation services to the Reno/Tahoe International Airport through a 3.0-mile pipeline and to the San Diego International Airport through a 4.3-mile pipeline. In March 1999, the Partnership acquired the fuels division of American Refining Group, Inc. (“ARG”) for approximately $13.7 million. The Partnership operated the former ARG processing business under the name of Buckeye Refining Company, LLC (“BRC”). BRC was sold to Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”) on October 25, 2000 for approximately $45.7 million. BRC processed transmix at its Indianola,

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Pennsylvania and Hartford, Illinois refineries. Transmix represents refined petroleum products, primarily fuel oil and gasoline that becomes commingled during normal pipeline operations. The refining process produced separate quantities of fuel oil, kerosene and gasoline that BRC then marketed at the wholesale level. In March 1999, the Partnership also acquired pipeline operating contracts and a 16-mile pipeline from Seagull Products Pipeline Corporation and Seagull Energy Corporation (“Seagull”) for approximately $5.8 million. The Partnership operates the assets acquired from Seagull under the name of Buckeye Gulf Coast Pipe Lines, LLC. BGC is an owner and contract operator of pipelines owned by major chemical companies in the Gulf Coast area. BGC leases its 16-mile pipeline to a major chemical company. In June 2000, the Partnership also acquired six petroleum products terminals from Agway Energy Products LLC (“Agway”) for approximately $20.7 million. The terminals acquired had an aggregate capacity of approximately 1.8 million barrels and are located in Brewerton, Geneva, Marcy, Rochester and Vestal, New York and Macungie, Pennsylvania. The Partnership operates the assets acquired from Agway under the name of Buckeye Terminals, LLC. On July 31, 2001, the Partnership acquired a refined products pipeline system and related terminals from affiliates of TransMontaigne Inc. for approximately $62.3 million. The assets included a 482-mile refined petroleum products pipeline that runs from Hartsdale, Indiana west to Fort Madison, Iowa and east to Toledo, Ohio, with an 11-mile pipeline connection between major storage terminals in Hartsdale and East Chicago, Indiana. These assets are operated by the Partnership under the name of Norco Pipe Line Company, LLC. The acquired assets also included 3.2 million barrels of pipeline storage and trans-shipment facilities in Hartsdale and East Chicago, Indiana and Toledo, Ohio; and four petroleum products terminals located in Bryan, Ohio; South Bend and Indianapolis, Indiana; and Peoria, Illinois. The storage and terminal assets are operated by Buckeye Terminals, LLC. On October 29, 2001, the Partnership acquired 6,805 shares of common stock of West Shore Pipe Line Company (“West Shore”) from TransMontaigne Pipeline Inc. for approximately $23.3 million. The common stock represents an 18.52 percent interest in West Shore. West Shore owns and operates a pipeline system that originates in the Chicago, Illinois area and extends north to Green Bay, Wisconsin and west and then north to Madison, Wisconsin. The pipeline system transports refined petroleum products to users in northern Illinois and Wisconsin. The other stockholders of West Shore are major oil companies. The pipeline is operated under contract by Citgo Pipeline Company. Refined Products Transportation The Partnership receives petroleum products from refineries, connecting pipelines and marine terminals, and transports those products to other locations. In 2002, refined petroleum products transportation accounted for approximately 86% of the Partnership’s consolidated revenues. The Partnership transported an average of approximately 1,101,400 barrels per day of refined products in 2002. The following table shows the volume and percentage of refined petroleum products transported over the last three years.

Volume and Percentage of Refined Petroleum Products Transported (1) (Volume in thousands of barrels per day)

Year ended December 31,

2002 2001 2000

Volume Percent Volume Percent Volume Percent

Gasoline.......................................................... 556.4 50.5% 540.7 49.6% 526.7 49.6% Jet Fuels .......................................................... 250.9 22.8 260.0 23.8 270.9 25.5 Middle Distillates (2)...................................... 265.4 24.1 266.8 24.5 248.6 23.4 Other Products ................................................ 28.7 2.6 22.9 2.1 15.3 1.5 Total................................................................ 1,101.4 100.0% 1,090.4 100.0% 1,061.5 100.0%

(1) Excludes local product transfers. (2) Includes diesel fuel, heating oil, kerosene and other middle distillates.

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The Partnership provides refined product pipeline service in the following states: Pennsylvania, New York, New Jersey, Indiana, Ohio, Michigan, Illinois, Connecticut, Massachusetts, Nevada, California and Florida. Pennsylvania—New York—New Jersey Buckeye serves major population centers in the states of Pennsylvania, New York and New Jersey through 943 miles of pipeline. Refined petroleum products are received at Linden, New Jersey from approximately 17 major source points, including 2 refineries, 6 connecting pipelines and 9 storage and terminalling facilities. Products are then transported through two lines from Linden, New Jersey to Allentown, Pennsylvania. From Allentown, the pipeline continues west, through a connection with Laurel, to Pittsburgh, Pennsylvania (serving Reading, Harrisburg, Altoona/Johnstown and Pittsburgh) and north through eastern Pennsylvania into New York (serving Scranton/Wilkes-Barre, Binghamton, Syracuse, Utica and Rochester and, via a connecting carrier, Buffalo). Buckeye leases capacity in one of the pipelines extending from Pennsylvania to upstate New York to a major oil company. Products received at Linden, New Jersey are also transported through one line to Newark International Airport and through two additional lines to J. F. Kennedy International and LaGuardia airports and to commercial bulk terminals at Long Island City and Inwood, New York. These pipelines supply J. F. Kennedy, LaGuardia and Newark airports with substantially all of each airport’s jet fuel requirements. Laurel transports refined petroleum products through a 345-mile pipeline extending westward from five refineries and a connection to Colonial Pipeline Company in the Philadelphia area to Reading, Harrisburg, Altoona /Johnstown and Pittsburgh, Pennsylvania. Indiana—Ohio—Michigan—Illinois Buckeye and Norco transport refined petroleum products through 2,336 miles of pipeline (of which 246 miles are jointly owned with other pipeline companies) in southern Illinois, central Indiana, eastern Michigan, western and northern Ohio and western Pennsylvania. A number of receiving and delivery lines connect to a central corridor which runs from Lima, Ohio, through Toledo, Ohio to Detroit, Michigan. Products are received at East Chicago, Indiana; Robinson, Illinois and at refinery and other pipeline connection points near Detroit, Toledo and Lima. Major market areas served include Peoria, Illinois; Huntington/Fort Wayne, Indianapolis and South Bend, Indiana; Bay City, Detroit and Flint, Michigan; Cleveland, Columbus, Lima and Toledo, Ohio; and Pittsburgh, Pennsylvania. Other Refined Products Pipelines Buckeye serves Connecticut and Massachusetts through 112 miles of pipeline (the “Jet Lines System”) that carry refined products from New Haven, Connecticut to Hartford, Connecticut and Springfield, Massachusetts. Everglades transports primarily turbine fuel on a 37-mile pipeline from Port Everglades, Florida to Hollywood-Ft. Lauderdale International Airport and Miami International Airport. Everglades supplies Miami International Airport with substantially all of its turbine fuel requirements. WesPac Pipeline-Reno Ltd., owns a 3.0-mile pipeline serving the Reno/Tahoe International Airport. WesPac Pipeline – San Diego Ltd. owns a 4.3-mile pipeline serving the San Diego International Airport. Both of these pipelines transport turbine fuel. Each of these WesPac entities is a joint venture between BPH and Kealine Partners in which BPH owns a 75 percent ownership interest. The Partnership also provides $8.9 million in debt financing to WesPac entities. Other Business Activities BPH provides bulk storage services through facilities located in Taylor, Michigan that have the capacity to store an aggregate of approximately 260,000 barrels of refined petroleum products. BT, a wholly-owned subsidiary of BPH, operates 14 terminals located in New York, Pennsylvania, Ohio, Indiana and Illinois that provide bulk storage and throughput services and have the capacity to store an aggregate of approximately 4,848,000 barrels of refined petroleum products. Together, these terminalling and storage activities provided approximately 8% of the Partnership’s revenue in 2002. BPH also owns an 18.52 percent stock interest in West Shore Pipe Line Company.

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West Shore owns and operates a pipeline system that originates in the Chicago, Illinois area and extends north to Green Bay, Wisconsin and west and then north to Madison, Wisconsin. The pipeline system transports refined petroleum products to users in northern Illinois and Wisconsin. The other stockholders of West Shore are major oil companies. West Shore is operated under contract by Citgo Pipeline Company. BGC, a wholly-owned subsidiary of BPH, is a contract operator of pipelines owned by major chemical companies in the state of Texas. BGC currently has seven operations and maintenance contracts in place. In addition, BGC owns a 16-mile pipeline located in the state of Texas that it leases to a third-party chemical company. A subsidiary of BGC also owns approximately 63 percent of a crude butadiene pipeline between Deer Park, Texas and Port Arthur, Texas that was completed in March 2003. In 2002, BGC’s contract operations provided approximately 6% of the Partnership’s revenue. BGC also provides engineering and construction management services to major chemical companies in the Gulf Coast area. Competition and Other Business Considerations The Operating Partnerships conduct business without the benefit of exclusive franchises from government entities. In addition, the Operating Partnerships pipeline operations generally operate as common carriers, providing transportation services at posted tariffs and without long-term contracts. The Operating Partnerships do not own the products they transport. Demand for the services provided by the Operating Partnerships derives from demand for petroleum products in the regions served and the ability and willingness of refiners, marketers and end-users to supply such demand by deliveries through the Operating Partnerships’ pipelines. Demand for refined petroleum products is primarily a function of price, prevailing general economic conditions and weather. The Operating Partnerships’ businesses are, therefore, subject to a variety of factors partially or entirely beyond their control. Multiple sources of pipeline entry and multiple points of delivery, however, have historically helped maintain stable total volumes even when volumes at particular source or destination points have changed. The Partnership’s business may in the future be affected by changing oil prices or other factors affecting demand for oil and other fuels. The Partnership’s business may also be impacted by energy conservation, changing sources of supply, structural changes in the oil industry and new energy technologies. The General Partner is unable to predict the effect of such factors. Changes in transportation and travel patterns in the areas served by the Partnership’s pipelines as well as further improvements in average fuel efficiency could adversely affect the Partnership’s results of operations and financial condition. In 2002, the pipeline transportation business had approximately 110 customers, most of which were either major integrated oil companies or large refined product marketing companies. The largest two customers accounted for 6.5 percent and 6.3 percent, respectively, of consolidated transportation revenues, while the 20 largest customers accounted for 64.3 percent of consolidated transportation revenues. Generally, pipelines are the lowest cost method for long-haul overland movement of refined petroleum products. Therefore, the Operating Partnerships’ most significant competitors for large volume shipments are other pipelines, many of which are owned and operated by major integrated oil companies. Although it is unlikely that a pipeline system comparable in size and scope to the Operating Partnerships’ pipeline system will be built in the foreseeable future, new pipelines (including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with the Operating Partnerships in particular locations. In the Midwest, several petroleum product pipeline expansions and two new petroleum product pipeline construction projects are in various stages of completion. Generally, these projects will increase the capacity to bring additional refined products into the Partnership’s service area. Because the Operating Partnerships own multiple pipelines throughout the Partnership’s service area and these projects do not impact local petroleum product supply and demand, the General Partner believes that the completion of these pipeline projects may result in volumes shifting from one Operating Partnership pipeline segment to another, but will not, in the aggregate, have a material adverse effect on the Operating Partnership’s results of operations or financial condition. The Operating Partnerships compete with marine transportation in some areas. Tankers and barges on the Great Lakes account for some of the volume to certain Michigan, Ohio and upstate New York locations during the

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approximately eight non-winter months of the year. Barges are presently a competitive factor for deliveries to the New York City area, the Pittsburgh area, Connecticut and Ohio. Trucks competitively deliver product in a number of areas served by the Operating Partnerships. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas served by the Operating Partnerships. The availability of truck transportation places a significant competitive constraint on the ability of the Operating Partnerships to increase their tariff rates. Privately arranged exchanges of product between marketers in different locations are an increasing but non-quantified form of competition. Generally, such exchanges reduce both parties’ costs by eliminating or reducing transportation charges. In addition, consolidation among refiners and marketers that has accelerated in recent years has altered distribution patterns, reducing demand for transportation services in some markets and increasing them in other markets. Distribution of refined petroleum products depends to a large extent upon the location and capacity of refineries. However, because the Partnership’s business is largely driven by the consumption of fuel in its delivery areas and the Operating Partnerships’ pipelines have numerous source points, the General Partner does not believe that the expansion or shutdown of any particular refinery would have a material effect on the business of the Partnership. The General Partner is unable to determine whether refinery expansions or shutdowns will occur or what their specific effect would be. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Forward-Looking Information – Competition and Other Business Conditions.” The Operating Partnerships’ mix of products transported tends to vary seasonally. Declines in demand for heating oil during the summer months are, to a certain extent, offset by increased demand for gasoline and jet fuel. Overall, operations have been only moderately seasonal, with somewhat lower than average volume being transported during March, April and May and somewhat higher than average volume being transported in November, December and January. Neither the Partnership nor any of the Operating Partnerships, other than BPH’s subsidiaries, has any employees. The Operating Partnerships are managed and operated by employees of Services Company, BGC, Norco and BT. In addition, Glenmoor provides certain management services to BMC, the General Partner and Services Company. At December 31, 2002, Services Company had a total of 506 full-time employees, 145 of whom were represented by two labor unions. At December 31, 2002, BGC had a total of 63 full-time, non-union employees, Norco had a total of 30 full-time, non-union employees and BT had a total of 22 full-time, non-union employees. The Operating Partnerships (and their predecessors) have never experienced any significant work stoppages or other significant labor problems. Capital Expenditures The Partnership incurs capital expenditures in order to maintain and enhance the safety and integrity of its pipelines and related assets, to expand the reach or capacity of its pipelines, to improve the efficiency of its operations or to pursue new business opportunities. During 2002 the Partnership incurred $71.6 million of capital expenditures, of which $28.2 million related to maintenance and integrity, $6.6 million related to expansion or cost reduction projects and $36.8 million related to the construction of a 90-mile crude butadiene pipeline. Financing for the Partnership’s capital expenditures was provided by cash from operations, borrowings under the Partnership’s revolving credit facilities and, with respect to the crude butadiene pipeline, $14.2 million from advances provided by two petrochemical companies involved in the project. The crude butadiene pipeline was completed in March 2003. In 2003, the Partnership anticipates capital expenditures of approximately $40 million, of which approximately $25 million is expected to relate to maintenance and integrity projects and approximately $15 million is expected to relate to expansion and cost reduction projects. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.”

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Regulation General Buckeye and Norco are interstate common carriers subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act and the Department of Energy Organization Act. FERC regulation requires that interstate oil pipeline rates be posted publicly and that these rates be “just and reasonable” and non-discriminatory. FERC regulation also enforces common carrier obligations and specifies a uniform system of accounts. In addition, Buckeye, Norco and the other Operating Partnerships are subject to the jurisdiction of certain other federal agencies with respect to environmental and pipeline safety matters. The Operating Partnerships are also subject to the jurisdiction of various state and local agencies, including, in some states, public utility commissions which have jurisdiction over, among other things, intrastate tariffs, the issuance of debt and equity securities, transfers of assets and pipeline safety. FERC Rate Regulation Buckeye's rates are governed by a market-based rate regulation program initially approved by FERC in March 1991 and subsequently extended. Under this program, in markets where Buckeye does not have significant market power, individual rate increases: (a) will not exceed a real (i.e., exclusive of inflation) increase of 15 percent over any two-year period (the "rate cap"), and (b) will be allowed to become effective without suspension or investigation if they do not exceed a "trigger" equal to the change in the Gross Domestic Product implicit price deflator since the date on which the individual rate was last increased, plus 2 percent. Individual rate decreases will be presumptively valid upon a showing that the proposed rate exceeds marginal costs. In markets where Buckeye was found to have significant market power and in certain markets where no market power finding was made: (i) individual rate increases cannot exceed the volume-weighted average rate increase in markets where Buckeye does not have significant market power since the date on which the individual rate was last increased, and (ii) any volume-weighted average rate decrease in markets where Buckeye does not have significant market power must be accompanied by a corresponding decrease in all of Buckeye's rates in markets where it does have significant market power. Shippers retain the right to file complaints or protests following notice of a rate increase, but are required to show that the proposed rates violate or have not been adequately justified under the market-based rate regulation program, that the proposed rates are unduly discriminatory, or that Buckeye has acquired significant market power in markets previously found to be competitive. The Buckeye program is an exception to the generic oil pipeline regulations issued under the Energy Policy Act of 1992. The generic rules rely primarily on an index methodology, whereby a pipeline is allowed to change its rates in accordance with an index (currently the Producer Price Index) that FERC believes reflects cost changes appropriate for application to pipeline rates. Alternatively, a pipeline is allowed to charge market-based rates if the pipeline establishes that it does not possess significant market power in a particular market. In addition, the rules provide for the rights of both pipelines and shippers to demonstrate that the index should not apply to an individual pipeline's rates in light of the pipeline's costs. The final rules became effective on January 1, 1995. The Buckeye program was subject to review by FERC in 2000 when FERC reviewed the index selected in the generic oil pipeline regulations. FERC decided to continue the generic oil pipeline regulations with no material changes and did not modify or discontinue Buckeye’s program. The General Partner cannot predict the impact that any change to Buckeye’s rate program would have on Buckeye’s operations. Independent of regulatory considerations, it is expected that tariff rates will continue to be constrained by competition and other market factors. Norco’s tariff rates are governed by the generic FERC index methodology, and therefore are subject to change annually according to the index. Environmental Matters The Operating Partnerships are subject to federal, state and local laws and regulations relating to the protection of the environment. Although the General Partner believes that the operations of the Operating Partnerships comply in all material respects with applicable environmental laws and regulations, risks of substantial liabilities are

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inherent in pipeline operations, and there can be no assurance that material environmental liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly rigorous environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or injuries to persons resulting from the operations of the Operating Partnerships, could result in substantial costs and liabilities to the Partnership. See “Legal Proceedings” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters.” The Oil Pollution Act of 1990 (“OPA”) amended certain provisions of the federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act (“CWA”), and other statutes as they pertain to the prevention of and response to petroleum product spills into navigable waters. The OPA subjects owners of facilities to strict joint and several liability for all containment and clean-up costs and certain other damages arising from a spill. The CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial liability for the costs of removing a spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground. Regulations are currently being developed under OPA and state laws that may impose additional regulatory burdens on the Partnership. Contamination resulting from spills or releases of refined petroleum products is not unusual in the petroleum pipeline industry. The Operating Partnerships’ pipelines cross numerous navigable rivers and streams. Although the General Partner believes that the Operating Partnerships comply in all material respects with the spill prevention, control and countermeasure requirements of federal laws, any spill or other release of petroleum products into navigable waters may result in material costs and liabilities to the Partnership. The Resource Conservation and Recovery Act (“RCRA”), as amended, establishes a comprehensive program of regulation of “hazardous wastes.” Hazardous waste generators, transporters, and owners or operators of treatment, storage and disposal facilities must comply with regulations designed to ensure detailed tracking, handling and monitoring of these wastes. RCRA also regulates the disposal of certain non-hazardous wastes. As a result of these regulations, certain wastes typically generated by pipeline operations are considered “hazardous wastes” which are subject to rigorous disposal requirements. The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” governs the release or threat of release of a “hazardous substance.” Releases of a hazardous substance, whether on or off-site, may subject the generator of that substance to liability under CERCLA for the costs of clean-up and other remedial action. Pipeline maintenance and other activities in the ordinary course of business generate “hazardous substances.” As a result, to the extent a hazardous substance generated by the Operating Partnerships or their predecessors may have been released or disposed of in the past, the Operating Partnerships may in the future be required to remedy contaminated property. Governmental authorities such as the Environmental Protection Agency, and in some instances third parties, are authorized under CERCLA to seek to recover remediation and other costs from responsible persons, without regard to fault or the legality of the original disposal. In addition to its potential liability as a generator of a “hazardous substance,” the property or right-of-way of the Operating Partnerships may be adjacent to or in the immediate vicinity of Superfund and other hazardous waste sites. Accordingly, the Operating Partnerships may be responsible under CERCLA for all or part of the costs required to cleanup such sites, which costs could be material. The Clean Air Act, amended by the Clean Air Act Amendments of 1990 (the “Amendments”), imposes controls on the emission of pollutants into the air. The Amendments required states to develop facility-wide permitting programs over the past several years to comply with new federal programs. Existing operating and air-emission requirements like those currently imposed on the Operating Partnerships are being reviewed by appropriate state agencies in connection with the new facility-wide permitting program. It is possible that new or more stringent controls will be imposed upon the Operating Partnerships through this permit review process. The Operating Partnerships are also subject to environmental laws and regulations adopted by the various states in which they operate. In certain instances, the regulatory standards adopted by the states are more stringent than applicable federal laws.

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In 1986, certain predecessor companies acquired by the Partnership, namely Buckeye Pipe Line Company and its subsidiaries (“Pipe Line”), entered into an Administrative Consent Order (“ACO”) with the New Jersey Department of Environmental Protection and Energy under the New Jersey Environmental Cleanup Responsibility Act of 1983 (“ECRA”) relating to all six of Pipe Line’s facilities in New Jersey. The ACO permitted the 1986 acquisition of Pipe Line to be completed prior to full compliance with ECRA, but required Pipe Line to conduct in a timely manner a sampling plan for environmental conditions at the New Jersey facilities and to implement any required clean-up plan. Sampling continues in an effort to identify areas of contamination at the New Jersey facilities, while clean-up operations have begun and have been completed at certain of the sites. The obligations of Pipe Line were not assumed by the Partnership and the costs of compliance have been and will continue to be paid by American Financial Group, Inc. Pipeline Regulation and Safety Matters The Operating Partnerships are subject to regulation by the United States Department of Transportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”) relating to the design, installation, testing, construction, operation, replacement and management of their pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain a plan of inspection and maintenance and to comply with such plans. The Pipeline Safety Reauthorization Act of 1988 requires coordination of safety regulation between federal and state agencies, testing and certification of pipeline personnel, and authorization of safety-related feasibility studies. The General Partner has initiated drug and alcohol testing programs to comply with the regulations promulgated by the Office of Pipeline Safety and DOT. HLPSA requires, among other things, that the Secretary of Transportation consider the need for the protection of the environment in issuing federal safety standards for the transportation of hazardous liquids by pipeline. The legislation also requires the Secretary of Transportation to issue regulations concerning, among other things, the identification by pipeline operators of environmentally sensitive areas; the circumstances under which emergency flow restricting devices should be required on pipelines; training and qualification standards for personnel involved in maintenance and operation of pipelines; and the periodic integrity testing of pipelines in unusually sensitive and high-density population areas by internal inspection devices or by hydrostatic testing. Effective in August 1999, the DOT issued its Operator Qualification Rule, which required a written program by April 27, 2001, for ensuring operators are qualified to perform tasks covered by the pipeline safety rules. All persons performing covered tasks must have been qualified under the program by October 28, 2002. The General Partner has identified the tasks that must be performed to comply with this rule, has filed its written plan and has qualified its employees and contractors as required. In addition, on December 1, 2000, DOT published notice of final rulemaking for Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Operators with 500 or more Miles of Pipeline). This rule sets forth regulations that require pipeline operators to assess, evaluate, repair and validate the integrity of hazardous liquid pipeline segments that, in the event of a leak or failure, could affect populated areas, areas unusually sensitive to environmental damage or commercially navigable waterways. Under the rule, pipeline operators were required to identify line segments which could impact high consequence areas by December 31, 2001. Pipeline operators were required to develop “Baseline Assessment Plans” for evaluating the integrity of each pipeline segment by March 31, 2002 and to complete an assessment of the highest risk 50 percent of line segments by September 30, 2004, with full assessment of the remaining 50 percent by March 31, 2008. Pipeline operators will thereafter be required to re-assess each affected segment in intervals not to exceed five years. In December 2002 the Pipeline Safety Improvement Act of 2002 (“PSIA”) became effective. The PSIA imposes additional obligations on pipeline operators, increases penalties for statutory and regulatory violations, and includes provisions prohibiting employers from taking adverse employment action against pipeline employees and contractors who raise concerns about pipeline safety within the company or with government agencies or the press. Many of the provisions of the PSIA are subject to regulations to be issued by the Department of Transportation. While the PSIA imposes additional operating requirements on pipeline operators, the General Partner does not believe that cost of compliance with the PSIA is likely to be material in the context of the Partnership’s operations. The General Partner believes that the Operating Partnerships currently comply in all material respects with HLPSA and other pipeline safety laws and regulations. However, the industry, including the Partnership, will, in the

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future, incur additional pipeline and tank integrity expenditures and the Partnership is likely to incur increased operating costs based on these and other government regulations. During 2002, the Partnership’s integrity expenditures increased to approximately $21 million. The General Partner expects integrity expenditures to continue at this level during 2003 in order to complete most of its initial assessment and pipeline improvements required by HLPSA. Once this initial assessment is complete, re-assessments are expected to cost significantly less and will be expensed. The General Partner believes these additional capital and operating expenditures with respect to HLSPA requirements will be offset, to some degree, by a reduced need for other facility improvements and lower operating expenses associated with improved pipeline facilities. The Operating Partnerships are also subject to the requirements of the Federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The General Partner believes that the Operating Partnerships’ operations comply in all material respects with OSHA requirements, including general industry standards, record- keeping, hazard communication requirements and monitoring of occupational exposure to benzene and other regulated substances. The General Partner cannot predict whether or in what form any new legislation or regulatory requirements might be enacted or adopted or the costs of compliance. In general, any such new regulations would increase operating costs and impose additional capital expenditure requirements on the Partnership, but the General Partner does not presently expect that such costs or capital expenditure requirements would have a material adverse effect on the Partnership’s results of operations or financial condition. Tax Treatment of Publicly Traded Partnerships under the Internal Revenue Code The Internal Revenue Code of 1986, as amended (the “Code”), imposes certain limitations on the current deductibility of losses attributable to investments in publicly traded partnerships and treats certain publicly traded partnerships as corporations for federal income tax purposes. The following discussion briefly describes certain aspects of the Code that apply to individuals who are citizens or residents of the United States without commenting on all of the federal income tax matters affecting the Partnership or the holders of LP units (“Unitholders”), and is qualified in its entirety by reference to the Code. UNITHOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISOR ABOUT THE FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES TO THEM OF AN INVESTMENT IN THE PARTNERSHIP. Characterization of the Partnership for Tax Purposes The Code treats a publicly traded partnership that existed on December 17, 1987, such as the Partnership, as a corporation for federal income tax purposes, unless, for each taxable year of the Partnership, under Section 7704(d) of the Code, 90 percent or more of its gross income consists of “qualifying income.” Qualifying income includes interest, dividends, real property rents, gains from the sale or disposition of real property, income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber), and gain from the sale or disposition of capital assets that produce such income. Because the Partnership is engaged primarily in the refined products pipeline transportation business, the General Partner believes that 90 percent or more of the Partnership’s gross income has been qualifying income. If this continues to be true and no subsequent legislation amends that provision, the Partnership will continue to be classified as a partnership and not as a corporation for federal income tax purposes. Passive Activity Loss Rules The Code provides that an individual, estate, trust or personal service corporation generally may not deduct losses from passive business activities, to the extent they exceed income from all such passive activities, against other (active) income. Income that may not be offset by passive activity losses includes not only salary and active business income, but also portfolio income such as interest, dividends or royalties or gain from the sale of property that produces portfolio income. Credits from passive activities are also limited to the tax attributable to any income from passive activities. The passive activity loss rules are applied after other applicable limitations on deductions, such as the at-risk rules and basis limitations. Certain closely held corporations are subject to slightly different rules that can also limit their ability to offset passive losses against certain types of income.

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Under the Code, net income from publicly traded partnerships is not treated as passive income for purposes of the passive loss rule, but is treated as non-passive income. Net losses and credits attributable to an interest in a publicly traded partnership are not allowed to offset a partner’s other income. Thus, a Unitholder’s proportionate share of the Partnership’s net losses may be used to offset only Partnership net income from its trade or business in succeeding taxable years or, upon a complete disposition of a Unitholder’s interest in the Partnership to an unrelated person in a fully taxable transaction, may be used to (i) offset gain recognized upon the disposition, and (ii) then against all other income of the Unitholder. In effect, net losses are suspended and carried forward indefinitely until utilized to offset net income of the Partnership from its trade or business or allowed upon the complete disposition to an unrelated person in a fully taxable transaction of the Unitholder’s interest in the Partnership. A Unitholder’s share of Partnership net income may not be offset by passive activity losses generated by other passive activities. In addition, a Unitholder’s proportionate share of the Partnership’s portfolio income, including portfolio income arising from the investment of the Partnership’s working capital, is not treated as income from a passive activity and may not be offset by such Unitholder’s share of net losses of the Partnership. Deductibility of Interest Expense The Code generally provides that investment interest expense is deductible only to the extent of a non-corporate taxpayer’s net investment income. In general, net investment income for purposes of this limitation includes gross income from property held for investment, gain attributable to the disposition of property held for investment (except for net capital gains for which the taxpayer has elected to be taxed at special capital gains rates) and portfolio income (determined pursuant to the passive loss rules) reduced by certain expenses (other than interest) which are directly connected with the production of such income. Property subject to the passive loss rules is not treated as property held for investment. However, the IRS has issued a Notice which provides that net income from a publicly traded partnership (not otherwise treated as a corporation) may be included in net investment income for purposes of the limitation on the deductibility of investment interest. A Unitholder’s investment income attributable to its interest in the Partnership will include both its allocable share of the Partnership’s portfolio income and trade or business income. A Unitholder’s investment interest expense will include its allocable share of the Partnership’s interest expense attributable to portfolio investments. Unrelated Business Taxable Income Certain entities otherwise exempt from federal income taxes (such as individual retirement accounts, pension plans and charitable organizations) are nevertheless subject to federal income tax on net unrelated business taxable income and each such entity must file a tax return for each year in which it has more than $1,000 of gross income from unrelated business activities. The General Partner believes that substantially all of the Partnership’s gross income will be treated as derived from an unrelated trade or business and taxable to such entities. The tax-exempt entity’s share of the Partnership’s deductions directly connected with carrying on such unrelated trade or business are allowed in computing the entity’s taxable unrelated business income. ACCORDINGLY, INVESTMENT IN THE PARTNERSHIP BY TAX-EXEMPT ENTITIES SUCH AS INDIVIDUAL RETIREMENT ACCOUNTS, PENSION PLANS AND CHARITABLE TRUSTS MAY NOT BE ADVISABLE. State Tax Treatment During 2002, the Partnership owned property or conducted business in the states of Pennsylvania, New York, New Jersey, Indiana, Ohio, Michigan, Illinois, Connecticut, Massachusetts, Florida, Texas, Nevada and California. A Unitholder will likely be required to file state income tax returns and to pay applicable state income taxes in many of these states and may be subject to penalties for failure to comply with such requirements. Some of the states have proposed that the Partnership withhold a percentage of income attributable to Partnership operations within the state for Unitholders who are non-residents of the state. In the event that amounts are required to be withheld (which may be greater or less than a particular Unitholder’s income tax liability to the state), such withholding would generally not relieve the non-resident Unitholder from the obligation to file a state income tax return.

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Certain Tax Consequences to Unitholders Upon formation of the Partnership in 1986, the General Partner elected twelve-year straight-line depreciation for tax purposes. For this reason, starting in 1999, the amount of depreciation available to the Partnership has been reduced significantly and taxable income has increased accordingly. Unitholders, however, will continue to offset Partnership income with individual LP Unit depreciation under their IRC section 754 election. Each Unitholder’s tax situation will differ depending upon the price paid and when LP Units were purchased. Generally, those who purchased LP Units within the past few years will have adequate depreciation to offset a considerable portion of Partnership income, while those who purchased LP Units more than several years ago will experience the full increase in taxable income. Unitholders are reminded that, in spite of the additional taxable income beginning in 1999, the current level of cash distributions exceed expected tax payments. Furthermore, sale of LP Units will result in taxable ordinary income as a consequence of depreciation recapture. UNITHOLDERS ARE ENCOURAGED TO CONSULT THEIR PROFESSIONAL TAX ADVISORS REGARDING THE TAX IMPLICATIONS TO THEIR INVESTMENT IN LP UNITS. Available Information The Partnership files annual, quarterly, and current reports and other documents with the SEC under the Securities Exchange Act of 1934. The public can obtain any documents that we file with the SEC at http://www.sec.gov. We also make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after filing such materials with, or furnishing such materials to, the SEC, on or through our Internet website, www.buckeye.com. We are not including the information contained on our Web site as a part of, or incorporating it by reference into, this Annual Report on Form 10-K. Item 2. Properties As of December 31, 2002, the principal facilities of the Partnership included 3,761 miles of 6-inch to 24-inch diameter pipeline, 49 pumping stations, 90 delivery points, various sized tanks having an aggregate capacity of approximately 14.7 million barrels and 15 bulk storage and terminal facilities. The Operating Partnerships and their subsidiaries own substantially all of these facilities. In general, the Partnership’s pipelines are located on land owned by others pursuant to rights granted under easements, leases, licenses and permits from railroads, utilities, governmental entities and private parties. Like other pipelines, certain of the Operating Partnerships’ and their subsidiaries rights are revocable at the election of the grantor or are subject to renewal at various intervals, and some require periodic payments. The Operating Partnerships and their subsidiaries have not experienced any revocations or lapses of such rights which were material to their business or operations, and the General Partner has no reason to expect any such revocation or lapse in the foreseeable future. Most delivery points, pumping stations and terminal facilities are located on land owned by the Operating Partnerships or their subsidiaries. The General Partner believes that the Operating Partnerships and their subsidiaries have sufficient title to their material assets and properties, possess all material authorizations and revocable consents from state and local governmental and regulatory authorities and have all other material rights necessary to conduct their business substantially in accordance with past practice. Although in certain cases the Operating Partnerships’ and their subsidiaries title to assets and properties or their other rights, including their rights to occupy the land of others under easements, leases, licenses and permits, may be subject to encumbrances, restrictions and other imperfections, none of such imperfections are expected by the General Partner to interfere materially with the conduct of the Operating Partnerships’ or their subsidiaries’ businesses. Item 3. Legal Proceedings The Partnership, in the ordinary course of business, is involved in various claims and legal proceedings, some of which are covered in whole or in part by insurance. The General Partner is unable to predict the timing or outcome

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of these claims and proceedings. Although it is possible that one or more of these claims or proceedings, if adversely determined, could, depending on the relative amounts involved, have a material effect on the Partnership for a future period, the General Partner does not believe that their outcome will have a material effect on the Partnership’s consolidated financial condition or results of operations. With respect to environmental litigation, certain Operating Partnerships (or their predecessors) have been named in the past as defendants in lawsuits, or have been notified by federal or state authorities that they are potentially responsible parties (“PRPs”) under federal laws or a respondent under state laws relating to the generation, disposal or release of hazardous substances into the environment. Typically, an Operating Partnership is one of many PRPs for a particular site and its contribution of total waste at the site is minimal. However, because CERCLA and similar statutes impose liability without regard to fault and on a joint and several basis, the liability of an Operating Partnership in connection with such proceedings could be material. Although there is no material environmental litigation pending against the Partnership or the Operating Partnerships at this time, claims may be asserted in the future under various federal and state laws, and the amount of such claims or the potential liability, if any, cannot be estimated. See “Business—Regulation—Environmental Matters.” Item 4. Submission of Matters to a Vote of Security Holders No matters were submitted to a vote of the holders of LP Units during the fourth quarter of the fiscal year ended December 31, 2002.

PART II

Item 5. Market for the Registrant’s LP Units and Related Unitholder Matters The LP Units of the Partnership are listed and traded principally on the New York Stock Exchange. The high and low sales prices of the LP Units in 2002 and 2001, as reported in the New York Stock Exchange Composite Transactions, were as follows: 2002 2001 Quarter High Low High Low First ............................................................................................ $40.200 $35.510 $34.990 $28.375Second ........................................................................................ 40.000 34.000 38.100 31.270Third ........................................................................................... 38.850 26.500 38.000 28.500Fourth ......................................................................................... 39.500 33.700 37.640 34.550 During the months of December 2002 and January 2003, the Partnership gathered tax information from its known LP Unitholders and from brokers/nominees. Based on the information collected, the Partnership estimates its number of beneficial LP Unitholders to be approximately 24,000. Cash distributions paid during 2001 and 2002 were as follows: Record Date

Payment Date

Amount Per Unit

February 6, 2001................................................................................................... February 28, 2001 $ 0.600 May 4, 2001.......................................................................................................... May 31, 2001 0.600 August 6, 2001 ..................................................................................................... August 31, 2001 0.625 November 6, 2001 ................................................................................................ November 30, 2001 0.625 February 6, 2002................................................................................................... February 28, 2002 $ 0.625 May 5, 2002.......................................................................................................... May 31, 2002 0.625 August 6, 2002 ..................................................................................................... August 30, 2002 0.625 November 6, 2002 ................................................................................................ November 29, 2002 0.625

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In general, the Partnership makes quarterly cash distributions of substantially all of its available cash less such retentions for working capital, anticipated expenditures and contingencies as the General Partner deems appropriate. On January 23, 2003, the Partnership announced a quarterly distribution of $0.625 per LP Unit payable on February 28, 2003, to Unitholders of record on February 6, 2003. The distribution was paid on February 28, 2003. On February 28, 2003, the Partnership sold 1,750,000 LP units in an underwritten public offering at a price of $36.01 per LP unit. Proceeds to the Partnership, net of underwriters’ discount of $1.62 per LP unit and estimated offering expenses, were approximately $59.7 million. Proceeds of the offering were used to reduce amounts outstanding under the Partnership’s revolving credit facilities (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” below). Item 6. Selected Financial Data The following tables set forth, for the period and at the dates indicated, the Partnership’s income statement and balance sheet data for each of the last five years. In January 1998, the General Partner approved a two-for-one unit split that became effective February 13, 1998. All unit and per unit information contained in this filing, unless otherwise noted, has been adjusted for the two for one split. The tables should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Report.

Year Ended December 31, 2002 2001 2000 1999 1998 (In thousands, except per unit amounts)

Income Statement Data: Transportation revenue............................................... $247,345 $232,397 $208,632 $200,828 $184,477 Depreciation and amortization (1).............................. 20,703 20,002 17,906 16,908 16,432 Operating income (1) (2) ........................................... 102,362 98,331 91,475 95,936 74,358 Interest and debt expense ........................................... 20,527 18,882 18,690 16,854 15,886 Income from continuing operations before extraordinary loss and discontinued operations ...... 71,902 69,402

64,467

71,101 52,007

Net income (3)............................................................ 71,902 69,402 96,331 76,283 52,007 Income per unit from continuing operations before extraordinary loss and discontinued operations ...... 2.65 2.56

2.38

2.63 1.93

Net income per unit .................................................... 2.65 2.56 3.56 2.82 1.93 Distributions per unit.................................................. 2.50 2.45 2.40 2.18 2.10

December 31, 2002 2001 2000 1999 1998 (In thousands)

Balance Sheet Data: Total assets ................................................................. $856,171 $807,560 $712,812 $661,078 $618,099 Long-term debt .......................................................... 405,000 373,000 283,000 266,000 240,000 General Partner’s capital ............................................ 2,870 2,834 2,831 2,548 2,390 Limited Partners’ capital ............................................ 355,475 351,057 346,551 314,441 296,095 Receivable from exercise of options .......................... 913 995 - - -

(1) Depreciation and amortization includes $832,000 and $461,000 in 2001 and 2000 related to goodwill acquired in the 2000 acquisition of six petroleum products terminals. Goodwill amortization ceased effective January 1, 2002 with the adoption of Statement of Financial Accounting Standards. No. 142 – “Goodwill and Other Intangible Assets.” See Note 7 to the Partnership’s consolidated financial statements.

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(2) Operating income for 1999 includes a one-time property tax expense reduction of $11.0 million following the settlement of a real property tax dispute with the City and State of New York.

(3) Net income includes income from discontinued operations of BRC of $5,682,000 in 2000 and $5,182,000

in 1999 and, in 2000, the gain of the sale of BRC of $26,182,000.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following is a discussion of the liquidity and capital resources and the results of operations of the Partnership for the periods indicated below. This discussion should be read in conjunction with the consolidated financial statements and notes thereto, which are included elsewhere in this report. Results of Operations Through its Operating Partnerships and their subsidiaries, the Partnership is principally engaged in the pipeline transportation of refined petroleum products and, between March 1999 and October 25, 2000, the refining of transmix. Products transported via pipeline include gasoline, jet fuel, diesel fuel, heating oil, kerosene and liquid propane gases (“LPGs”). The Partnership’s revenues derived from the transportation of refined petroleum products are principally a function of the volumes of refined petroleum products transported by the Partnership, which are in turn a function of the demand for refined petroleum products in the regions served by the Partnership’s pipelines, and the tariffs or transportation fees charged for such transportation. The Partnership is also engaged, through BPH, BT and BGC, in the terminalling and storage of petroleum products and in contract operations of pipelines for third parties. Revenues for each of the three years in the period ended December 31, 2002 were as follows: Revenues 2002

2001

(in thousands) 2000

Pipeline transportation $214,052 $206,332 $193,845 Terminalling, storage and rentals 18,859 16,353 7,092 Contract operations 14,434 9,712 7,695 Total $247,345 $232,397 $208,632 Results of operations are affected by factors that include general economic conditions, weather, competitive conditions, demand for refined petroleum products, seasonal factors and regulation. See “Business— Competition and Other Business Considerations.” 2002 Compared With 2001 Total revenue for the year ended December 31, 2002 was $247.3 million, $14.9 million or 6.4 percent greater than revenue of $232.4 million in 2001. Revenue from pipeline transportation was $214.1 million in 2002 compared to $206.3 million in 2001. Of the $7.8 million increase in pipeline transportation revenue, $4.3 million is related to a full-year of Norco operations in 2002 compared to five months of Norco operations in 2001. Volumes delivered during 2002 averaged 1,101,400 barrels per day, 11,000 barrels per day or 1.0 percent greater than volume of 1,090,400 barrels per day delivered in 2001. Revenue from the transportation of gasoline of $114.1 million increased by $6.5 million, or 6.0 percent, from 2001 levels. $2.0 million of the increase in gasoline transportation revenue was related to a full-year of Norco operations. Total gasoline volumes of 556,400 barrels per day in 2002 were 15,700 barrels per day, or 2.9 percent greater than 2001 volumes of 540,700 barrels per day. Norco gasoline volumes for a full-year of operations in 2002 were 17,200 barrels per day compared to 16,800 barrels per day for five months of operations in 2001. In the East, gasoline volumes of 245,700 barrels per day were approximately 9,400 barrels per day, or 4.0 percent, greater than 2001 volumes. The increase was primarily due to greater deliveries to the upstate New York and Pittsburgh, Pennsylvania areas. In the Midwest, gasoline volumes of 164,000 barrels per day were 6,900 barrels per day, or 4.0

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percent, less than gasoline volumes delivered during 2001. Demand for gasoline transportation was generally lower throughout the region with the largest declines occurring in the Detroit and Bay City, Michigan areas. Long Island System gasoline volumes of 111,300 barrels per day were up 5,700 barrels per day, or 5.4% percent, due to additional available capacity on this system following reductions in turbine fuel demand after September 11, 2001. On the Jet Lines System, gasoline volumes of 18,200 barrels per day were 2,700 barrels per day, or 12.8 percent, less than 2001 volumes due to lower transportation demand in the Hartford, Connecticut area. Revenue from the transportation of distillate of $57.7 million increased by $0.4 million, or 0.7 percent, from 2001 levels. Norco’s distillate transportation revenue increased by $1.9 million in 2002 reflecting a full year of operations. Total volumes of 265,400 barrels per day in 2002 were 1,400 barrels per day, or 0.5 percent less than 2001 distillate volumes of 266,800 barrels per day. Norco distillate volumes for a full-year of operations in 2002 were 12,900 barrels per day compared to 12,800 barrels per for five months of operations in 2001. In the East, distillate volumes of 145,000 barrels per day were approximately 5,300 barrels per day, or 3.5 percent, less than 2001 volumes. In the Midwest, distillate volumes of 68,100 barrels per day were 1,200 barrels per day, or 1.8 percent, less than volumes delivered during 2001. Long Island System distillate volumes of 18,400 barrels per day were down 700 barrels per day or 3.9 percent less than volumes delivered during 2001. On the Jet Lines system, distillate volumes of 20,700 barrels per day were 1,800 barrels per day, or 8.1 percent, less than 2001 volumes. Distillate volumes declined during the first quarter of 2002 compared to the first quarter 2001 due to milder than normal winter conditions. During the fourth quarter 2002, distillate volumes increased over fourth quarter 2001 volumes as winter conditions returned to more normal levels. The increase, however, did not fully offset the decline that occurred during the first quarter of the year. Revenue from the transportation of jet fuel of $36.9 million decreased by $0.4 million, or 1.0 percent, from 2001 levels. Norco does not transport turbine fuel. In May, 2001 WesPac commenced turbine fuel deliveries to San Diego airport. WesPac’s turbine fuel revenue was up $0.9 million primarily due to a full-year of deliveries to San Diego Airport during 2002. Total jet fuel volumes of 250,900 barrels per day in 2002 were 9,100 barrels per day, or 3.5 percent less than 2001 jet fuel volumes of 260,000 barrels per day. WesPac’s jet fuel volumes of 11,700 barrels per day were up 3,600 barrels per day due to a full year of deliveries to San Diego Airport. Deliveries to New York City airports declined by 9,100 barrels per day, or 6.6 percent. Deliveries to Pittsburgh Airport declined by 2,100 barrels per day, or 18.0 percent, while deliveries to Miami airport declined 2,900 barrels per day, or 5.4 percent. Volumes to all major airports declined as a result of reduced airline travel following the terrorist attacks on September 11, 2001. Although deliveries to major airports have improved from the dramatic decline immediately following September 11, 2001, the outlook for further recovery of turbine fuel volumes to pre-September 11, 2001 levels is uncertain due to airline schedule reductions, reduced consumer air travel and the threat of further terrorist attacks. Terminalling, storage and rental revenue of $18.9 million increased by $2.5 million in 2002 primarily due to a full year of Norco operations.

Contract operation services revenues of $14.4 million increased by $4.7 million due to additional contracts obtained by BGC during 2002 and 2001. Contract operations revenues typically consist of costs reimbursable under the contracts plus an operator’s fee. Accordingly, revenues from these operations carry a lower gross profit percentage than revenues from pipeline transportation or terminalling, storage and rentals. The Partnership’s costs and expenses for 2002 were $145.0 million compared to $134.1 million for 2001. BGC’s costs and expenses increased by $4.5 million over 2001 as a result of additional contract services provided. A full year of Norco operations resulted in an additional $4.4 million of operating expense. Other increases of $2.0 million are primarily related to general wage increases, increases in payroll overhead costs, increases in the use of outside services, increases in power costs related to additional pipeline volumes and higher insurance premiums. Other income and expense for 2002 was a net cost of $30.5 million compared to $28.9 million in 2001. The increase is primarily due to higher interest expense on additional borrowings during 2002 and 2001 related to acquisitions and certain capital expenditures.

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2001 Compared With 2000 Total revenue for the year ended December 31, 2001 was $232.4 million, $23.8 million or 11.4 percent greater than revenue of $208.6 million in 2000. Revenue derived from the pipeline transportation of refined products was $206.3 million in 2001 compared to $193.8 million in 2000. Of the $12.5 million increase in pipeline transportation revenue, $2.7 million of the increase was related to the Norco acquisition. Volumes delivered during 2001 averaged 1,090,400 barrels per day, 28,900 barrels per day or 2.7 percent greater than volume of 1,061,500 barrels per day delivered in 2000. The Norco acquisition represented 14,700 barrels per day of the volumes transported in 2001. Revenue from the transportation of gasoline increased by $5.5 million, or 5.4 percent, from 2000 levels, of which $1.2 million was related to the Norco acquisition. In the East, deliveries to the Pittsburgh, Pennsylvania and upstate New York areas increased compared to 2000 volumes due to strong demand there. In the Midwest, volumes and revenue declined compared to 2000 volumes primarily as the result of decreased deliveries to the Bay City, Michigan area. Deliveries to Bay City were unusually high in 2000 following the closure of a refinery in that area. Revenue from the transportation of distillate volumes increased by $3.8 million, or 7.0 percent, over 2000 levels, of which $1.3 million was related to the Norco acquisition. Distillate deliveries for the year were up primarily due to the colder than normal weather experienced during the first and second quarter of 2001. Revenue from the transportation of jet fuel decreased by $0.2 million, or 0.6 percent, from 2000 levels. Norco does not transport turbine fuel. In May, 2001 WesPac commenced turbine fuel deliveries to San Diego airport. This new business added $1.4 million to 2001 revenues. Through September 11, 2001, turbine fuel revenue was approximately 4 percent above prior year levels. However, the terrorist attacks of September 11th greatly curtailed air travel during the balance of September and the fourth quarter of 2001. Turbine fuel deliveries declined by 18 percent overall during the fourth quarter of 2001. Turbine fuel volumes improved in December 2001 as air travel began to recover but was still down by approximately 10 percent overall from December 2000 levels. Deliveries to New York area airports were particularly affected, with a 24 percent decline in October 2000, a 28 percent decline in November 2001 and an 18 percent decline in December 2001 from year earlier volumes. This greater than average decline reflects the larger percentage of international flights at these airports as compared to other jet fuel delivery locations. Revenue from the transportation of liquefied petroleum products (“LPG”) increased by $1.3 million, or 49.3 percent, over 2000 levels. Norco does not transport LPG product. The increase in LPG revenues is related to primarily to new business at Lima, Ohio. Terminalling, storage and rental revenue of $16.4 million increased by $9.3 million in 2001. $3.4 million is due to an increase in terminalling and storage revenue of which $1.9 million is related to the Norco acquisition with the balance primarily resulting from a full year of operations related to the Agway terminal acquisition on June 30, 2000. Rental revenue increased by $5.2 million during 2001 of which $2.1 million is related to the Norco and Agway acquisitions. Contract operation services revenue of $9.7 million increased by $2.0 million due to additional contracts obtained by BGC during 2001 and 2000. Costs and expenses for 2001 were $134.1 million compared to costs and expenses of $117.2 million for 2000. BGC’s costs and expenses increased by $4.4 million over 2000 as result of additional contract services provided. Another $4.4 million of the expense increase is related to the Norco and Agway acquisitions. Other increases of $8.1 million are primarily related to general wage increases, increased payroll overhead costs, an increase in the use of outside services, increased power costs related to additional pipeline deliveries and higher insurance premiums. Other expenses for 2001 were $28.9 million compared to $27.0 million in 2000. A $1.6 million gain realized on the sale of property in 2000 did not recur in 2001. In addition, incentive compensation payments to the General Partner that are based on the level of Partnership distributions were approximately $0.6 million greater during 2001 than 2000 due to an increase in the level of cash distributions paid to limited partners. Investment income increased primarily as the result of a $0.6 million gain on the tendering of preferred stock back to Aerie Networks, Inc.

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(“Aerie”). The preferred stock had been issued by Aerie in exchange for assisting Aerie with its development of a fiber optics network along the Partnership’s rights-of-way. Discontinued Operations In 2000, net income of $5.7 million from the discontinued operations of BRC resulted from revenues of $172.5 million offset by costs and expenses of $166.8 million. BRC was sold to Kinder Morgan Energy Partners, L.P. for an aggregate sale price of $45.7 million on October 25, 2000. The sale resulted in a gain of $26.2 million (see Item 8, “Financial Statements and Supplementary Data”). Tariff Changes Effective July 1, 2002, certain of the Operating Partnerships implemented tariff increases that were expected to generate approximately $3.8 million in additional annual revenue. Effective July 1, 2001, certain of the Operating Partnerships implemented tariff increases that were expected to generate approximately $4.1 million in additional revenue per year. Effective July 1, 2000, certain of the Operating Partnerships implemented tariff increases that were expected to generate approximately $2.0 million in additional revenue per year. Liquidity and Capital Resources The Partnership’s financial condition at December 31, 2002, 2001, and 2000 is highlighted in the following comparative summary: Liquidity and Capital Indicators

As of December 31, 2002 2001 2000

Current ratio (1) ............................................................................................................ 1.4 to 1 1.5 to 1 2.0 to 1Ratio of cash, cash equivalents and trade receivables to current liabilities................... .9 to 1 .8 to 1 1.5 to 1Working capital (in thousands) (2) ............................................................................... $13,092 $15,430 $28,749Ratio of total debt to total capital (3) ............................................................................ .53 to 1 .51 to 1 .45 to 1Book value (per Unit)(4)............................................................................................... $13.15 $12.98 $12.91

(1) current assets divided by current liabilities (2) current assets minus current liabilities (3) long-term debt divided by long-term debt plus total partners’ capital (4) total partners’ capital divided by Units outstanding at year-end.

During 2002, 2001 and 2000, the Partnership’s principal sources of liquidity were cash from operations and borrowings under its revolving credit facilities. Additionally, in 2000, the Partnership received the proceeds from the sale of BRC. In February 2003 the Partnership issued 1,750,000 LP units. The Partnership’s principal uses of cash are for capital expenditures, investments and acquisitions and distributions to unitholders. The Partnership anticipates that cash from operations and amounts available under its revolving credit facilities will be sufficient to fund its cash requirements for 2003. Cash Flows from Operations Cash flows from operations were $93.1 million in 2002 compared to $81.0 million 2001. Income from continuing operations for 2002 was $71.9 million. Income from continuing operations, before depreciation and amortization of $20.7 million, increased by $3.2 million to $92.6 million in 2002 from $89.4 million in 2001. Changes in current assets and liabilities resulted in a net source of cash of $0.6 million in 2002 compared to a net cash use of $5.3 million in 2001. In 2002, increases in trade receivables and inventories were more than offset by reductions in prepaid and other assets. In 2001, increases in trade receivables and inventories were coupled with an increase in prepaid and other assets of $4.5 million, principally related to operations at BGC. Changes in other noncurrent assets and liabilities resulted in a net cash use of $1.2 million in 2002 compared to a net cash use of $3.5 million in 2001.

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Cash from operations of $81.0 million in 2001 increased by $6.3 million compared to $74.7 million in 2000. Income from continuing operations for 2001 was $69.4 million. Income from continuing operations, before depreciation and amortization of $20.0 million, increased by $7.1 million to $89.4 million in 2001 from $82.3 million in 2000. Changes in current assets and liabilities resulted in a net cash use of $8.4 million in 2000, principally related to increases in trade receivables, inventory and prepaid expenses. Changes in noncurrent assets and liabilities resulted in a net source of cash of $1.2 million in 2000. Cash Flows from Investing Activities Net cash used in investing activities totaled $72.8 million in 2002 compared to $122.3 million in 2001 and $14.0 million in 2000. Substantially all of the 2002 investing activities relate to capital expenditures. In 2001, the Partnership invested $62.3 million in the acquisition of Norco and $23.6 million for an approximate 18% interest in West Shore. In 2000, the Partnership invested $20.7 million to acquire six petroleum products terminals from Agway, and received $45.6 million proceeds from the sale of BRC. The Partnership had no acquisition or investment expenditures in 2002. Capital expenditures for the years ended December 31, 2002, 2001 and 2000 are summarized below: Capital Expenditures 2002 2001 2000 (in millions) Sustaining capital expenditures: Operating infrastructure ................................ $ 7.0 $ 10.1 $ 6.0 Pipeline and tank integrity ............................ 21.2 15.8 7.2 Total sustaining ......................................... 28.2 25.9 13.2 Expansion and cost reduction ........................... 6.6 10.8 27.1 Subtotal............................................................. 34.8 36.7 40.3 Investment in Gulf Coast Pipeline Project........ 36.8 - - Total ............................................................... $ 71.6 $ 36.7 $ 40.3 The Partnership’s 2002 capital expenditures of $34.8 million (excluding the $36.8 million related to the pipeline project discussed below) declined by $1.9 million from $36.7 million in 2001. Of this total, $28.2 million related to sustaining expenditures compared to $25.9 million in 2001 and $13.2 million in 2000. During 2002, the Partnership emphasized its pipeline and tank integrity projects, including electronic internal inspections, other integrity assessments and associated repairs, as part of a comprehensive program to meet increased safety and environmental standards (see Part I, “Business-Environmental Matters” and “Business-Pipeline Regulation and Safety Matters”). Under an agreement with three major petrochemical companies (the “Agreement”), BGC has constructed a 90-mile crude butadiene pipeline (the “Gulf Coast Pipeline Project”). The pipeline originates at a Shell Chemicals, L.P. facility in Deer Park, Texas and terminates at a chemical plant owned by Sabina Petrochemicals, LLC in Port Arthur, Texas. As of December 31, 2002, the Partnership had expended $36.8 million to construct the pipeline which is included in the Partnership’s 2002 capital expenditures. In addition, as of December 31, 2002 two of the petrochemical companies had advanced $14.2 million to the Partnership based on certain construction milestones. These advances are included in other non-current liabilities in the financial statements of the Partnership. As of March 2003, the pipeline was substantially complete and BGC holds an approximate 63 percent interest in two partnerships (the “Pipeline Partnerships”) which own the pipeline. The two petrochemical companies own the remaining 37 percent minority interest in the Pipeline Partnerships. Separately, BGC has entered into an agreement to operate and maintain the pipeline for the Pipeline Partnerships and the Pipeline Partnerships have entered into a long-term agreement with Sabina Petrochemicals, LLC to provide pipeline transportation throughput services. The Partnership expects to spend approximately $40 million in capital expenditures in 2003, of which approximately $25 million will relate to sustaining expenditures and approximately $15 million to expansion and cost reduction projects. Sustaining capital expenditures, in addition to pipeline integrity, include renewals and replacements of tank floors and roofs, upgrades to field instrumentation and cathodic protection systems, and replacement of mainline pipe and valves. Expansion and cost reduction expenditures include projects to facilitate

21

increased pipeline volumes, extend the pipeline incrementally to new facilities, expand terminal facilities or improve the efficiency of operations. Of the planned 2003 sustaining capital expenditures of $25 million, approximately $15 to $20 million is expected to relate to pipeline and tank integrity projects. During 2002, 2001 and 2000, the Partnership accelerated its expenditures related to pipeline and tank integrity projects, and anticipates that such expenditures will begin to decline commencing in 2004 upon completion of most of the long-distance pipeline integrity inspections. As discussed below under Critical Accounting Policies and Estimates, the Partnership’s initial integrity expenditures are capitalized as part of pipeline cost when such expenditures improve or extend the life of the pipeline or related assets. Subsequent integrity expenditures are expensed as incurred. Accordingly, over time, integrity expenditures will shift from capital to operating expenditures. Cash Flows from Financing Activities During 2002, the Partnership increased its borrowings under its revolving credit facility by $32 million, principally to fund its investment in the Gulf Coast Pipeline Project as well as a portion of its other capital expenditures. Additionally, as noted above, the Partnership received $14.2 million in advances from two of the three petrochemical companies participating in the Gulf Coast Pipeline Project. During 2001, the Partnership increased its borrowings under its revolving credit facilities by $90.0 million, principally to fund the Norco acquisition and the investment in West Shore Pipeline Company as well as a portion of its capital expenditures. During 2000, the Partnership increased its borrowings under its revolving credit facilities by $17 million, principally related to the acquisition of the six petroleum products terminals from Agway. Distributions to unitholders totaled $67.9 million in 2002 compared to $66.5 million and $65.0 million in 2001 and 2000, respectively. Debt Obligations, Credit Facilities and Other Financing At December 31, 2002, the Partnership had $405.0 million in outstanding long-term debt, consisting of $240.0 million of Senior Notes (Series 1997A through 1997D) (the “Senior Notes”) and $165.0 million outstanding under its 5-year revolving credit facility. The Senior Notes are due in 2024 and accrue interest at an average rate of 6.94%. At December 31, 2002, borrowings under the 5-year revolving credit facility accrued interest at a weighted average rate of 2.71%. In 2001, the Partnership entered into a $277.5 million 5-year Revolving Credit Agreement and a $92.5 million 364-day Revolving Credit Agreement with a syndicate of banks led by SunTrust Bank. In September 2002, the Partnership entered into a new 364-day Revolving Credit Agreement with another syndicate of banks also led by SunTrust Bank and reduced the maximum amount borrowable to $85.0 million. At that time certain covenants contained in both agreements (the “Credit Facilities”) were amended to eliminate the requirement of an investment grade rating from either Standard and Poor’s or Moody’s Investor Services. Together, the Credit Facilities permit borrowings up to $362.5 million subject to certain limitations contained in the Credit Facility agreements. Borrowings bear interest at SunTrust Bank’s base rate or at a rate based on the London Interbank Offered Rate (“LIBOR”) at the option of the Partnership. The $362.5 million is available under the Credit Facilities until September 2003 with $277.5 million available thereafter until September 2006. The Partnership anticipates renewing the 364-day facility prior to its expiration in September 2003. These Credit Facilities replaced revolving credit agreements which had previously been established with another bank. The indenture of the Senior Notes (the “Indenture”) and the Credit Facilities contain similar covenants which together (a) limit outstanding indebtedness of the Partnership and Buckeye based on certain financial ratios, (b) prohibit the Partnership from creating or incurring certain liens on its property, (c) prohibit the Partnership from disposing of property which is material to its operations and (d) limit consolidation, merger and asset transfers by the Partnership. Covenants under the Indenture apply to Buckeye, Laurel and Buckeye Pipe Line Company of Michigan, L.P., whereas the covenants under the Credit Facilities apply to the Partnership and all of its direct and substantially all of its indirect subsidiaries. At December 31, 2002, all parties were in compliance with the covenants in the Credit Facilities and the Indenture. At December 31, 2002, the Partnership had approximately $196.8 million available under the Credit Facilities.

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In October 2002 the Partnership filed an amended shelf registration statement for the issuance, from time to time of up to an aggregate of $300 million of the Partnership’s LP units. In January 2003 the Partnership filed a separate shelf registration statement for the issuance from time to time of up to an aggregate of $300 million of the Partnership’s debt securities. In February 2003 the Partnership issued 1,750,000 LP units at a price of $36.01 per LP unit. Net proceeds to the Partnership, after underwriters’ discount of $1.62 per unit and estimated offering expenses were approximately $59.7 million. Proceeds from the offering were used to reduce amounts outstanding under the Credit Facilities. Operating Leases The Operating Partnerships lease certain land and rights-of-way. Minimum future lease payments for these leases as of December 31, 2002 are approximately $3.4 million for each of the next five years. Substantially all of these lease payments may be canceled at any time should the leased property no longer be required for operations. The General Partner leases space in an office building and certain office equipment and charges these costs to the Operating Partnerships. Buckeye leases certain computing equipment and automobiles. Future minimum lease payments under these noncancelable operating leases at December 31, 2002 were as follows: $734,000 for 2003, $649,000 for 2004, $657,000 for 2005, $483,000 for 2006, $59,000 for 2007 and none thereafter. Buckeye entered into an energy services agreement for certain main line pumping equipment and the natural gas requirements to fuel this equipment at its Linden, New Jersey facility. Under the energy services agreement, which is designed to reduce power costs at the Linden facility, Buckeye is required to pay a minimum of $1,743,000 annually over the next nine years. This minimum payment is based on an annual minimum usage requirement of the natural gas engines at the rate of $0.049 per kilowatt hour equivalent. In addition to the annual usage requirement, Buckeye is subject to minimum usage requirements during peak and off-peak periods. Buckeye’s use of the natural gas engines has exceeded the minimum annual requirement in each of the three years ended December 31, 2002. Rent expense under operating leases was $7,285,000, $7,700,000 and $8,855,000 for 2002, 2001 and 2000, respectively. Included in rent expense for operating leases is $1,191,000 related to discontinued operations for 2000. Contractual obligations are summarized in the follow table: Payments Due by Period (In thousands)

Contractual Obligations

Total

Less than 1 year

1-3 years

4-5 years

Thereafter

Long-Term Debt ........................................ $405,000 $ - $ - $165,000 $240,000 Operating Leases ....................................... 2,582 734 1,306 542 - Other Long-Term Obligations ................... 15,687 1,743 3,486 3,486 6,972 Total Contractual Cash Obligations........... $423,269 $ 2,477 $ 4,792 $169,028 $246,972 Environmental Matters The Operating Partnerships are subject to federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations, as well as the Partnership’s own standards relating to protection of the environment, cause the Operating Partnerships to incur current and ongoing operating and capital expenditures. During 2002, the Operating Partnerships incurred operating expenses of $1.2 million and, at December 31, 2002, had $7.5 million accrued for environmental matters. Expenditures, both capital and operating, relating to environmental matters are expected to continue due to the Partnership’s commitment to maintain high environmental standards and to increasingly rigorous environmental laws. Various claims for the cost of cleaning up releases of hazardous substances and for damage to the environment resulting from the activities of the Operating Partnerships or their predecessors have been asserted and may be asserted in the future under various federal and state laws. The General Partner believes that the generation, handling

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and disposal of hazardous substances by the Operating Partnerships and their predecessors have been in material compliance with applicable environmental and regulatory requirements. The total potential remediation costs to be borne by the Operating Partnerships relating to these clean-up sites cannot be reasonably estimated and could be material. With respect to each site, however, the Operating Partnership involved is typically one of several or as many as several hundred PRPs that would share in the total costs of clean-up under the principle of joint and several liability. Although the Partnership has made a provision for certain legal expenses relating to these matters, the General Partner is unable to determine the timing or outcome of any pending proceedings or of any future claims and proceedings. See “Business—Regulation—Environmental Matters” and “Legal Proceedings.” Competition and Other Business Conditions Several major refiners and marketers of petroleum products announced strategic alliances or mergers in recent years. These alliances or mergers have the potential to alter refined product supply and distribution patterns within the Operating Partnerships’ market area resulting in both gains and losses of volume and revenue. While the General Partner believes that individual delivery locations within its market area may have significant gains or losses, it is not possible to predict the overall impact these alliances or mergers may have on the Operating Partnerships’ business. However, the General Partner does not believe that these alliances or mergers will have a material adverse effect on the Partnership’s results of operations or financial condition. In the Midwest, several petroleum product pipeline expansions and two new petroleum product pipeline construction projects are in various stages of completion. While these projects have the potential to alter supply sources with respect to the Partnership’s service area, they are not expected to have a material adverse effect on the Operating Partnership’s results of operations or financial condition. Certain changes in refined petroleum product specifications are likely to impact the transportation of refined petroleum products over the next several years. Methyl-Tertiary-Butyl-Ether (“MTBE”), a gasoline additive used for air pollution control purposes, is scheduled to be phased out of use in certain states commencing in 2004. The phase-out of MTBE may result in a reduction in gasoline volumes delivered in the Partnership’s service area. The Partnership is unable to quantify the amount by which its transportation volumes might be affected by the phase-out of MTBE. In addition, new requirements for the use of ultra low-sulfur diesel fuel could require significant capital expenditures at certain locations in order to permit the Partnership to handle this new product grade. At this time the Partnership is unable to predict the timing or amount of capital or operating expenditures that would be required to enable the Partnership to transport and store ultra low-sulfur diesel fuel. Employee Stock Ownership Plan Services Company provides an employee stock ownership plan (the “ESOP”) to substantially all of its regular full-time employees, except those covered by certain labor contracts. The ESOP owns all of the outstanding common stock of Services Company. At December 31, 2002, the ESOP was directly obligated to a third-party lender for $47.5 million of 7.24 percent Notes (the “ESOP Notes”). The ESOP Notes are secured by Services Company common stock and are guaranteed by Glenmoor and certain of its affiliates. The proceeds from the issuance of the ESOP Notes were used to purchase Services Company common stock. Services Company stock is released to employee accounts in the proportion that current payments of principal and interest on the ESOP Notes bear to the total of all principal and interest payments due under the ESOP Notes. Individual employees are allocated shares based on the ratio of their eligible compensation to total eligible compensation. Eligible compensation generally includes base salary, overtime payments and certain bonuses. Services Company stock allocated to employees receives stock dividends in lieu of cash, while cash dividends are used to pay principal and interest on the ESOP Notes. The Partnership contributed 2,573,146 LP Units to Services Company in August 1997 in exchange for the elimination of the Partnership’s obligation to reimburse BMC for certain executive compensation costs, a reduction of the incentive compensation paid by the Partnership to BMC under the existing incentive compensation agreement, and other changes that made the ESOP a less expensive fringe benefit for the Partnership. Funding for the ESOP Notes is provided by distributions that Services Company receives on the LP Units that it owns and from cash payments from the Partnership, as required to cover any shortfall between the distributions that Services Company receives on the LP Units that it owns and amounts currently due under the ESOP Notes (the “top-up”

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reserve). The Partnership will also incur ESOP-related costs for routine administrative costs and taxes associated with annual taxable income or the sale of LP units, if any. Total ESOP related costs charged to earnings were $1.2 million in 2002 and $1.1 million during each of 2001 and 2000. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to select appropriate accounting principles from those available, to apply those principles consistently and to make reasonable estimates and assumptions that affect revenues and associated costs as well as reported amounts of assets and liabilities. Generally, the timing and amount of revenue recognized by an organization is among the most critical of accounting policies to be adopted. For its pipeline operations, which constitutes approximately 86% the Partnership’s revenues, the Partnership recognizes revenue as the product is delivered to customers. Terminalling and storage revenues, representing approximately 8% of the Partnership’s revenues, are recognized as the services are provided. Revenues from contract pipeline operations, representing approximately 6% of the Partnership’s revenues, are recognized as the services are provided. Revenues for contract operations include both direct costs to be reimbursed by the customer under the contract and an operating fee. In all cases, the Partnership’s revenue recognition approximates billings to the customer. Because the Partnership’s customers generally consist of major integrated oil companies, petroleum refiners and petrochemical companies, collections experience has historically been good and the Partnership has not required an allowance for bad debts. Some of the Partnership’s customers consist of major airlines, some of whom have experienced financial difficulties or even bankruptcy following the events of September 11, 2001. However, the Partnership’s credit monitoring policies, coupled with its ability to require prepayment of transportation charges, has limited its exposure to losses from potentially uncollectible accounts. Bad debts, when they occur, are written off as a charge to revenue. Approximately 85% of the Partnership’s consolidated assets consist of property, plant and equipment. Property plant and equipment consists of pipeline and related transportation facilities and equipment, including land, rights-of-way, buildings and leasehold improvements and machinery and equipment. Pipeline assets are generally self-constructed, using either contractors or the Partnership’s own employees. Additions and improvement to the pipeline are capitalized based on the cost of the improvement while repairs and maintenance are expensed. Pipeline integrity expenditures are capitalized the first time such expenditures are incurred, when such expenditures improve or extend the life of the pipeline or related assets. Subsequent integrity expenditures are expensed as incurred. During 2002, 2001 and 2000, the Partnership capitalized $21.2 million, $15.8 million and $7.2 million, respectively, of integrity expenditures. Over the next several years, the Partnership expects integrity expenditures, both capital and operating, to range between $15 million and $20 million per year. During this time, the portion of expenditures capitalized is expected to decrease and the portion recorded as expense is expected to increase. As discussed under Environmental Matters above, the Operating Partnerships are subject to federal, state and local laws and regulations relating to the protection of the environment. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Partnership’s commitment to a formal plan of action. Accrued environmental remediation related expenses include estimates of direct costs of remediation and indirect costs related to the remediation effort, such as compensation and benefits for employees directly involved in the remediation activities and fees paid to outside engineering, consulting and law firms. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. During 2002, the Operating Partnerships incurred operating expenses of $1.2 million and, at December 31, 2002, had $7.5 million accrued for environmental matters. The environmental accruals are revised as new matters arise, or as new facts in connection with environmental remediation projects require a revision of estimates previously made with respect to the probable cost of such remediation projects.

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In the event a known environmental liability results in expenditures that exceed the amount that has been accrued in connection with the matter, the additional expenditures would result in an increase in expenses and a reduction in income, in the period when the additional expense is incurred. Based on its experience, however, the Partnership believes that the amounts it has accrued for the future costs related to environmental liabilities is reasonable. Related Party Transactions With respect to related party transactions see Note 18 to the consolidated financial statements and Item 13 of Part III included elsewhere in this report. Recent Accounting Pronouncements In June 2001, the FASB issued two new pronouncements: SFAS No. 141, “Business Combinations”, and SFAS No. 142, “Goodwill and Other Intangible Assets”. SFAS 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. The Norco acquisition was accounted for in accordance with the provisions of SFAS 141. SFAS 142 is effective for fiscal years beginning after December 15, 2001 with respect to all goodwill and other intangible assets recognized in an entity’s statement of financial position at that date, regardless of when those assets were initially recognized. As a result of SFAS 142, the Partnership’s goodwill of $11,355,000 is no longer subject to amortization. In June 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations”. SFAS No. 143, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. While the Partnership has not completed its analysis, the General Partner does not believe that the adoption of SFAS 143 will have a material impact on the Partnership’s financial statements. In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. SFAS 144 addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 was effective for fiscal years beginning after December 15, 2001 and did not have a material impact on the Partnership’s financial statements. In May 2002, the FASB issued SFAS No. 145, “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections”. SFAS 145 rescinds the automatic treatment of gains or losses from extinguishments of debt as extraordinary unless they meet the criteria for extraordinary items as outlined in APB No. 30, “Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions”. SFAS No. 145 also requires sale-leaseback accounting for certain lease modifications that have economic effects similar to a sale-leaseback transaction and makes various technical corrections to existing pronouncements. SFAS No. 145 is effective for fiscal years beginning after December 31, 2002. The Partnership does not expect the adoption of SFAS No. 145 to have a material effect on its consolidated financial position or results of operations. In June 2002 the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 nullifies the guidance provided in Emerging Issues Task Force (“EITF”) Issue 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” Generally, SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred, rather than when management commits to a plan of exit or disposal as is called for by EITF Issue No. 94-3. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002, with earlier application encouraged. In November 2002, the FASB issued Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 established requirements for accounting and disclosure of guarantees issued to third parties for various transactions. The accounting requirements of FIN 45 are applicable to guarantees issued after December 31, 2002. The disclosure requirements of FIN 45 are applicable to financial statements issued for periods ending after December 15, 2002.

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The Partnership has included the applicable disclosures in its financial statements and does not anticipate that the accounting provisions of FIN 45 will have a material impact on its financial statements. In December 2002 the FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation – Transition and Disclosure”, SFAS 148 amended the implementation provisions of SFAS 123 and required changes in disclosures in financial statements. The provisions of SFAS 148 were applicable for years ending after December 15, 2002 except for certain quarterly disclosures, which were applicable for interim periods beginning after December 15, 2002. The Company has not changed its method of accounting for stock-based compensation and, therefore, is subject only to the revised disclosure provisions of SFAS 148. Such disclosures have been included in the Partnership’s financial statements and quarterly disclosures will be provided commencing in the first quarter of 2003. In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities (“FIN 46”). FIN 46 establishes accounting and disclosure requirements for ownership interests in entities that have certain financial or ownership characteristics (sometimes known as “Special Purpose Entities”). FIN 46 is applicable for variable interest entities created after January 31, 2003 and becomes effective in the first fiscal year or interim accounting period beginning after June 15, 2003 for variable interest entities created before February 1, 2003. The Partnership does not anticipate that the provisions of FIN 46 will have a material impact on its financial statements. Forward-Looking Information Information contained above in this Management’s Discussion and Analysis and elsewhere in this Report on Form 10-K with respect to expected financial results and future events is forward-looking, based on our estimates and assumptions and subject to risk and uncertainties. For those statements, the Partnership and the General Partner claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. The following important factors could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) changes in laws and regulations, including safety, tax and accounting matters; (3) competitive pressures from alternative energy sources; (4) liability for environmental claims; (5) improvements in energy efficiency and technology resulting in reduced demand; (6) labor relations; (7) changes in real property tax assessments; (8) regional economic conditions; (9) market prices of petroleum products and the demand for those products in the Partnership’s service territory; (10) disruptions to the air travel system; (11) security issues relating to the Partnership’ assets; and (12) interest rate fluctuations and other capital market conditions. These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events. Item 7A. Quantitative and Qualitative Disclosures About Market Risk The Partnership is exposed to market risks resulting from changes in interest rates. Market risk represents the risk of loss that may impact the Partnership’s results of operations, the consolidated financial position or operating cash flows. The Partnership is not exposed to any market risk due to rate changes on its Senior Notes but is exposed to market risk related to the interest rate on the Credit Facilities. Market Risk – Trading Instruments Prior to the sale of BRC, the Partnership hedged a substantial portion of its exposure to inventory price fluctuations related to its BRC business with commodity futures contracts for the sale of gasoline and fuel oil. Losses related to commodity futures contracts included in earnings from discontinued operations were $6.7 million for 2000. Currently the Partnership has no derivative instruments and does not engage in hedging activity.

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Market Risk – Other than Trading Instruments The Partnership has market risk exposure on its Credit Facilities due to its variable rate pricing that is based on the bank’s base rate or at a rate based on LIBOR. At December 31, 2002, the Partnership had $165.0 million in outstanding debt under its Credit Facilities that was subject to market risk. Based on the amount outstanding at December 31, 2002, a 1 percent increase or decrease in the applicable rate under the Credit Facilities will result in an interest expense fluctuation of approximately $1.65 million. As of December 31, 2001, the Partnership had $133 million in outstanding debt that was subject to market risk.

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Item 8. Financial Statements and Supplementary Data

BUCKEYE PARTNERS, L.P.

Index to Financial Statements and Financial Statement Schedules

Page Number

Financial Statements and Independent Auditors’ Report: Independent Auditors’ Report ........................................................................................................... 29 Consolidated Statements of Income—For the years ended December 31, 2002, 2001 and 2000 ........................................................................................................................................

30

Consolidated Balance Sheets—December 31, 2002 and 2001.......................................................... 31 Consolidated Statements of Cash Flows—For the years ended December 31, 2002, 2001 and 2000 ...............................................................................................................................

32

Notes to Consolidated Financial Statements ..................................................................................... 33 Financial Statement Schedule and Independent Auditors’ Report: Independent Auditors’ Report ........................................................................................................... S-1 Schedule I—Registrant’s Condensed Financial Information ............................................................ S-2 Schedules other than those listed above are omitted because they are either not applicable or not required or the information required is included in the consolidated financial statements or notes thereto.

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INDEPENDENT AUDITORS’ REPORT

To the Partners of Buckeye Partners, L.P.: We have audited the accompanying consolidated balance sheets of Buckeye Partners, L.P. and its subsidiaries (the “Partnership”) as of December 31, 2002 and 2001, and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 7 to the consolidated financial statements, effective January 1, 2002, the Partnership changed its method of accounting for goodwill and other intangible assets to conform to Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.” DELOITTE & TOUCHE LLP Philadelphia, Pennsylvania March 19, 2003

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BUCKEYE PARTNERS, L.P. CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per unit amounts) Year Ended December 31, Notes 2002 2001 2000

Transportation revenue ............................................................ 2,4 $ 247,345 $ 232,397 $ 208,632 Costs and expenses Operating expenses .......................................................... 6,18 110,670 101,965 87,498 Depreciation and amortization ......................................... 2,7,9,10 20,703 20,002 17,906 General and administrative expenses ............................... 18 13,610 12,099 11,753 Total costs and expenses .............................................. 144,983 134,066 117,157

Operating income .................................................................... 102,362 98,331 91,475

Other income (expenses) Investment income ........................................................... 1,952 1,526 596 Interest and debt expense ................................................. (20,527) (18,882) (18,690) Minority interests and other ............................................. 18 (11,885) (11,573) (8,914) Total other income (expenses) ..................................... (30,460) (28,929) (27,008)

Income from continuing operations......................................... 71,902 69,402 64,467 Earnings of discontinued operations........................................ 5 - - 5,682 Gain on sale of discontinued operations .................................. 5 - - 26,182 Income from discontinued operations...................................... - - 31,864

Net income............................................................................... $ 71,902 $ 69,402 $ 96,331

Net income allocated to General Partner ................................. 19 $ 646 $ 601 $ 868 Net income allocated to Limited Partners................................ 19 $ 71,256 $ 68,801 $ 95,463

Earnings per Partnership Unit Income from continuing operations allocated to General and Limited Partners per Partnership Unit ...................................

$ 2.65

$ 2.56

$ 2.38

Income from discontinued operations allocated to General and Limited Partners per Partnership Unit.............................

-

-

1.18

Earnings per Partnership Unit.................................................. $ 2.65 $ 2.56 $ 3.56 Earnings Per Partnership Unit – assuming dilution: Income from continuing operations allocated to General and Limited Partners per Partnership Unit.............................

$ 2.64

$ 2.55

$ 2.38

Income from discontinued operations allocated to General and Limited Partners per Partnership Unit.............................

-

-

1.17

Earnings per Partnership Unit.................................................. $ 2.64 $ 2.55 $ 3.55

See Notes to consolidated financial statements.

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BUCKEYE PARTNERS, L.P. CONSOLIDATED BALANCE SHEETS

(In thousands) December 31, Notes 2002 2001 Assets Current assets Cash and cash equivalents ............................................... 2 $ 11,208 $ 12,946 Trade receivables............................................................. 2 17,203 13,753 Inventories....................................................................... 2 8,424 7,591 Prepaid and other current assets ...................................... 8 7,007 13,441 Total current assets........................................................ 43,842 47,731 Property, plant and equipment, net ..................................... 2,4,9 727,450 670,439 Goodwill............................................................................. 7 11,355 11,355 Other non-current assets ..................................................... 10,16 73,524 78,035 Total assets .................................................................... $ 856,171 $ 807,560 Liabilities and partners’ capital Current liabilities Accounts payable ............................................................ $ 8,062 $ 7,416 Accrued and other current liabilities ............................... 5,11,18 22,688 24,885 Total current liabilities ................................................. 30,750 32,301 Long-term debt ................................................................... 12 405,000 373,000 Minority interests ............................................................... 3,498 3,307 Other non-current liabilities................................................ 13,14,18 59,491 46,056 Total liabilities ............................................................. 498,739 454,664 Commitments and contingent liabilities ............................. 6,17 - - Partners’ capital General Partner................................................................... 19 2,870 2,834 Limited Partner................................................................... 19 355,475 351,057 Receivable from exercise of options................................... 19 (913) (995) Total partners’ capital .................................................. 357,432 352,896 Total liabilities and partners’ capital ............................ $ 856,171 $ 807,560 See Notes to consolidated financial statements.

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BUCKEYE PARTNERS, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (In thousands)

Year Ended December 31, Notes 2002 2001 2000

Cash flows from operating activities: Net income.............................................................................................. $ 71,902 $ 69,402 $ 96,331 Income from discontinued operations..................................................... - - (5,682) Gain on sale of discontinued operations ................................................. - - (26,182) Income from continuing operations ........................................................ 71,902 69,402 64,467 Adjustments to reconcile income to net cash provided by operating activities: Gain on sale of property, plant and equipment ................................. - - (1,582) Gain on sale of investments .............................................................. - (620) - Depreciation and amortization .......................................................... 7,9,10 20,703 20,002 17,906 Minority interests .............................................................................. 1,046 960 1,094 Change in assets and liabilities: Trade receivables........................................................................... (3,450) (2,748) (3,058) Inventories..................................................................................... (833) (1,032) (1,159) Prepaid and other current assets ................................................... 6,434 (4,480) (4,227) Accounts payable .......................................................................... 646 828 82 Accrued and other current liabilities ............................................. (2,197) 2,169 (49) Other non-current assets.................................................................................. (434) (1,515) (838) Other non-current liabilities .......................................................... (722) (1,968) 2,059 Total adjustments from operating activities............................... 21,193 11,596 10,228

Net cash provided by continuing operations .............................. 93,095 80,998 74,695

Net cash provided by discontinued operations .......................... - - 3,576

Cash flows from investing activities: Capital expenditures................................................................................ 9 (71,608) (36,667) (40,267) Acquisitions ............................................................................................ - (62,283) (20,693) Investment in West Shore Pipe Line Company ...................................... - (23,268) - Net (expenditures for) proceeds from disposal of property, plant and equipment................................................................................... (1,161) (779) 1,261 Proceeds from sale of investments.......................................................... - 711 - Proceeds from sale of discontinued operations ....................................... - - 45,696 Net cash used in investing activities .......................................... (72,769) (122,286) (14,003)

Cash flows from financing activities: Debt issuance costs ................................................................................. 12 - (1,339) - Proceeds from exercise of unit options ................................................... 566 576 1,013 Distributions to minority interests........................................................... (855) (755) (845) Advances related to pipeline project ....................................................... 9 14,157 - -

Proceeds from issuance of long-term debt .............................................. 12 46,000 210,000 46,000 Payment of long-term debt...................................................................... 12 (14,000) (120,000) (29,000) Distributions to unitholders..................................................................... 19,20 (67,932) (66,464) (64,951) Net cash (used in) provided by financing activities................... (22,064) 22,018 (47,783)

Net (decrease) increase in cash and cash equivalents ................................ (1,738) (19,270) 16,485Cash and cash equivalents at beginning of year ........................................ 12,946 32,216 15,731Cash and cash equivalents at end of year .................................................. $ 11,208 $ 12,946 $ 32,216

Supplemental cash flow information: Cash paid during the year for interest (net of amount capitalized) ......... $ 20,628 $ 19,053 $ 17,828 Capitalized interest ................................................................................. $ 2,083 $ 1,102 $ 1,157

See Notes to consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, 2002 AND 2001 AND

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 1. ORGANIZATION Buckeye Partners, L.P. (the “Partnership”) is a master limited partnership organized in 1986 under the laws of the state of Delaware. The Partnership’s principal line of business is the transportation of refined petroleum products for major integrated oil companies, large refined product marketing companies and major end users of petroleum products on a fee basis through facilities owned and operated by the Partnership. The Partnership owns approximately 99 percent limited partnership interests in Buckeye Pipe Line Company, L.P. (“Buckeye”), Laurel Pipe Line Company, L.P. (“Laurel”), Everglades Pipe Line Company, L.P. (“Everglades”) and Buckeye Pipe Line Holdings, L.P. (“BPH” formerly Buckeye Tank Terminals Company, L.P.) These entities are hereinafter referred to as the “Operating Partnerships.” BPH owns directly, or indirectly, a 100 percent interest in each of Buckeye Terminals, LLC (“BT”), Norco Pipe Line Company, LLC (“Norco”), Buckeye Gulf Coast Pipe Lines, L.P. (“BGC”). BPH also owns a 75 percent interest in WesPac Pipeline-Reno Ltd., WesPac Pipeline-San Diego, Ltd. and related WesPac entities (collectively known as “WesPac”) and an 18.52 percent interest in West Shore Pipe Line Company. Buckeye Pipe Line Company (the “General Partner”) serves as the general partner to the Partnership. As of December 31, 2002, the General Partner owned approximately a 1 percent general partnership interest in the Partnership and approximately a 1 percent general partnership interest in each Operating Partnership, for an effective 2 percent interest in the Partnership. The General Partner is a wholly-owned subsidiary of Buckeye Management Company (“BMC”). BMC is a wholly-owned subsidiary of Glenmoor, Ltd. (“Glenmoor”). Glenmoor is owned by certain directors and members of senior management of the General Partner and trusts for the benefit of their families and by certain other management employees of Buckeye Pipe Line Services Company (“Services Company”). Services Company employs substantially all of the employees that work for the Operating Partnerships. At December 31, 2002, Services Company had 506 full-time employees. Services Company entered into a Services Agreement with BMC and the General Partner in August 1997 to provide services to the Partnership and the Operating Partnerships through March 2011. Services Company is reimbursed by BMC or the General Partner for its direct and indirect expenses, which in turn are reimbursed by the Partnership, except for certain executive compensation costs. (see Note 18). BT, Norco and BGC directly employed 115 full-time employees at December 31, 2002. Buckeye is one of the largest independent pipeline common carriers of refined petroleum products in the United States, with 2,909 miles of pipeline serving 9 states. Laurel owns a 345-mile common carrier refined products pipeline located principally in Pennsylvania. Norco owns a 482-mile refined products pipeline system located primarily in Illinois, Indiana and Ohio. Everglades owns a 37-mile refined products pipeline in Florida. Buckeye, Laurel, Norco and Everglades conduct the Partnership’s refined products pipeline business. BPH and its subsidiaries provide bulk storage service through facilities with an aggregate capacity of 5.1 million barrels of refined petroleum products. BGC is a contract operator of pipelines owned by major chemical companies in the State of Texas. WesPac provides pipeline transportation service to Reno/Tahoe International and San Diego International airports. On March 4, 1999, the Partnership acquired the fuels division of American Refining Group, Inc. (“ARG”) for approximately $13.7 million. The Partnership operated the former ARG processing business under the name of Buckeye Refining Company, LLC (“BRC”). BRC was sold to Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”) on October 25, 2000 for approximately $45.7 million. BRC processed transmix at its Indianola, Pennsylvania and Hartford, Illinois refineries. Transmix represents refined petroleum products, primarily fuel oil and gasoline that become commingled during normal pipeline operations. The refining process produced separate quantities of fuel oil, kerosene and gasoline that BRC then marketed at the wholesale level (see Note 5).

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On March 31, 1999, the Partnership acquired pipeline operating contracts and a 16-mile pipeline from Seagull Products Pipeline Corporation and Seagull Energy Corporation (“Seagull”) for approximately $5.8 million. The Partnership operates the assets acquired from Seagull under the name of Buckeye Gulf Coast Pipe Lines, LLC. BGC is an owner and contract operator of pipelines owned by major chemical companies in the Gulf Coast area. BGC leases its 16-mile pipeline to a chemical company. In June 2000, the Partnership also acquired six petroleum products terminals from Agway Energy Products LLC for approximately $20.7 million. The terminals acquired had an aggregate capacity of approximately 1.8 million barrels and are located in Brewerton, Geneva, Marcy, Rochester and Vestal, New York and Macungie, Pennsylvania. The Partnership operates the assets acquired from Agway under the name of Buckeye Terminals, LLC. On July 31, 2001, the Partnership acquired a refined products pipeline system and related terminals from affiliates of TransMontaigne Inc. for approximately $62.3 million. The assets included a 482-mile refined petroleum products pipeline that runs from Hartsdale, Indiana west to Fort Madison, Iowa and east to Toledo, Ohio, with an 11-mile pipeline connection between major storage terminals in Hartsdale and East Chicago, Indiana. These assets are operated by the Partnership under the name of Norco Pipe Line Company, LLC. The acquired assets also included 3.2 million barrels of pipeline storage and trans-shipment facilities in Hartsdale and East Chicago, Indiana and Toledo, Ohio; and four petroleum products terminals located in Bryan, Ohio; South Bend and Indianapolis, Indiana; and Peoria, Illinois. The storage and terminal assets are operated by Buckeye Terminals, LLC. On October 29, 2001, the Partnership acquired 6,805 shares of common stock of West Shore Pipe Line Company (“West Shore”) from TransMontaigne Pipeline Inc. for approximately $23.3 million. The common stock represents an 18.52 percent interest in West Shore. West Shore owns and operates a pipeline system that originates in the Chicago, Illinois area and extends north to Green Bay, Wisconsin and west and then north to Madison, Wisconsin. The pipeline system transports refined petroleum products to users in northern Illinois and Wisconsin. The other stockholders of West Shore are major oil companies. The pipeline is operated under contract by Citgo Pipeline Company. The investment in West Shore is accounted for using the cost basis of accounting. The Partnership maintains its accounts in accordance with the Uniform System of Accounts for Pipeline Companies, as prescribed by the Federal Energy Regulatory Commission (“FERC”). Buckeye and Norco are subject to rate regulation as promulgated by FERC. Reports to FERC differ from the accompanying consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“generally accepted accounting principles”), generally in that such reports calculate depreciation over estimated useful lives of the assets as prescribed by FERC. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation The financial statements include the accounts of the Operating Partnerships on a consolidated basis. All significant intercompany transactions have been eliminated in consolidation. Use of Estimates The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America necessarily requires management to make estimates and assumptions. These estimates and assumptions, which may differ from actual results, will affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenue and expense during the reporting period. Financial Instruments and Hedging Activities The fair values of financial instruments are determined by reference to various market data and other valuation techniques as appropriate. Unless otherwise disclosed, the fair values of financial instruments approximate their recorded values (see Note 12). Statement of Financial Accounting Standards No. 133 “Accounting for Financial

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Instruments and Hedging Activities” (“SFAS 133”) was effective January 1, 2001. The Partnership did not have financial instruments or transactions subject to the provisions of SFAS 133 during 2002 or 2001, the periods affected by SFAS 133. Cash and Cash Equivalents All highly liquid debt instruments purchased with a maturity of three months or less are classified as cash equivalents. Revenue Recognition Revenue from the transportation of refined petroleum products is recognized as products are delivered to customers. Such customers include major integrated oil companies, major petroleum refiners, major petrochemical companies, large regional marketing companies and large commercial airlines. The consolidated Partnership’s customer base was approximately 110 in 2002. No customer contributed more than 10 percent of total revenue during 2002. The Partnership does not maintain an allowance for doubtful accounts due to its favorable collections experience. The Partnership also derives revenue from terminalling operations, rentals and contract services for the operation of facilities and pipelines not directly owned by the Partnership. Revenue from such operations is recognized as the services are performed. Contract services revenue typically includes costs to be reimbursed by the customer plus an operator fee. Inventories Inventories, consisting of materials and supplies such as: pipe, valves, pumps, electrical/electronic components, drag reducing agent and other miscellaneous items are carried at the lower of cost or market based on the first-in, first-out method. Property, Plant and Equipment Property, plant and equipment consist primarily of pipeline and related transportation facilities and equipment. For financial reporting purposes, depreciation on pipe assets is calculated using the straight-line method over the estimated useful life of 50 years. Other assets are depreciated on a straight-line basis over an estimated life of 5 to 50 years. Additions and betterments are capitalized and maintenance and repairs are charged to income as incurred. Generally, upon normal retirement or replacement, the cost of property (less salvage) is charged to the depreciation reserve, which has no effect on income. Goodwill

Effective January 1, 2002, the Partnership no longer amortizes goodwill. In 2001 and 2000, the Partnership amortized goodwill on a straight-line basis over a period of fifteen years (see Recent Accounting Pronouncements below and Note 7). The Partnership assesses its goodwill annually for potential impairment based on the market value of its business compared to its book value.

Long-Lived Assets The Partnership regularly assesses the recoverability of its long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Partnership assesses recoverability based on estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposal. The measurement is based on the fair value of the asset. Income Taxes For federal and state income tax purposes, the Partnership and Operating Partnerships are not taxable entities. Accordingly, the taxable income or loss of the Partnership and Operating Partnerships, which may vary substantially from income or loss reported for financial reporting purposes, is generally includable in the federal and state income

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tax returns of the individual partners. As of December 31, 2002 and 2001, the Partnership’s reported amount of net assets for financial reporting purposes exceeded its tax basis by approximately $327 million and $306 million, respectively. Environmental Expenditures Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Partnership’s commitment to a formal plan of action. Accrued environmental remediation related expenses include direct costs of remediation and indirect costs related to the remediation effort, such as compensation and benefits for employees directly involved in the remediation activities and fees paid to outside engineering, consulting and law firms. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. Pensions Services Company maintains a defined contribution plan (see Note 14), defined benefit plans (see Note 14) and an employee stock ownership plan (see Note 16) which provide retirement benefits to substantially all of its regular full-time employees, Norco employees, BGC employees and BT employees. Certain hourly employees of Services Company are covered by a defined contribution plan under a union agreement (see Note 14). Postretirement Benefits Other Than Pensions Services Company provides postretirement health care and life insurance benefits for certain of its retirees (see Note 14). Certain other retired employees are covered by a health and welfare plan under a union agreement (see Note 14). Unit Option and Distribution Equivalent Plan The Partnership has adopted Statement of Financial Accounting Standards No. 123 (“SFAS 123”), “Accounting for Stock-Based Compensation,” which requires expanded disclosures of stock-based compensation arrangements with employees. SFAS 123 encourages, but does not require, compensation cost to be measured based on the fair value of the equity instrument awarded. It allows the Partnership to continue to measure compensation cost for these plans using the intrinsic value based method of accounting prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). The Partnership has elected to continue to recognize compensation cost based on the intrinsic value of the equity instrument awarded as promulgated in APB 25.

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If compensation cost had been determined based on the fair value at the time of the grant dates for awards consistent with SFAS 123, the Partnership’s net income and earnings per share would have been as indicated by the proforma amounts below:

(In thousands, except per Unit amounts) 2002 2001 2000

Net income as reported $71,902 $69,402 $96,331 Stock-based employee compensation cost included in net income

1

7

20

Stock-based employee compensation cost that would have been included in net income under the fair value method

(179)

(130)

(95) Pro forma net income as if the fair value method had been applied to all awards

$71,724

$69,279

$96,256

Basic earnings per unit As reported and Pro forma $2.65 $2.56 $3.56

Diluted earnings per unit As reported and Pro forma $2.64 $2.55 $3.55

Comprehensive Income The Partnership does not have any items of comprehensive income other than net income. Accordingly, net income and comprehensive income are the same. Reclassifications Certain prior year amounts have been reclassified to conform to current year presentation. Recent Accounting Pronouncements In June 2001, the FASB issued two new pronouncements: SFAS No. 141, “Business Combinations”, and SFAS No. 142, “Goodwill and Other Intangible Assets”. SFAS 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. The Norco acquisition was accounted for in accordance with the provisions of SFAS 141. SFAS 142 is effective for fiscal years beginning after December 15, 2001 with respect to all goodwill and other intangible assets recognized in an entity’s statement of financial position at that date, regardless of when those assets were initially recognized. As a result of SFAS 142, the Partnership’s goodwill of $11,355,000 is no longer subject to amortization. In June 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations”. SFAS No. 143, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. While the Partnership has not completed its analysis, the General Partner does not believe that the adoption of SFAS 143 will have a material impact on the Partnership’s financial statements. In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. SFAS 144 addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 was effective for fiscal years beginning after December 15, 2001, and its adoption did not have a material impact on the Partnership’s financial statements.

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In May 2002, the FASB issued SFAS No. 145, “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections”. SFAS 145 rescinds the automatic treatment of gains or losses from extinguishments of debt as extraordinary unless they meet the criteria for extraordinary items as outlined in APB No. 30, “Reporting the Results of Operations, Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions”. SFAS No. 145 also requires sale-leaseback accounting for certain lease modifications that have economic effects similar to a sale-leaseback transaction and makes various technical corrections to existing pronouncements. SFAS No. 145 is effective for fiscal years beginning after December 31, 2002. The Partnership does not expect the adoption of SFAS No. 145 to have a material effect on its consolidated financial position or results of operations. In June 2002 the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 nullifies the guidance provided in Emerging Issues Task Force (“EITF”) Issue 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” Generally, SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred, rather than when management commits to a plan of exit or disposal as is called for by EITF Issue No. 94-3. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002, with earlier application encouraged. In November 2002, the FASB issued Interpretation No. 45 “Guarantor’s Accounting Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 established requirements for accounting and disclosure of guarantees issued to third parties for various transactions. The accounting requirements of FIN 45 are applicable to guarantees issued after December 31, 2002. The disclosure requirements of FIN 45 are applicable to financial statements issued for periods ending after December 15, 2002. The Partnership has included the applicable disclosures in its financial statements and does not anticipate that the accounting provisions of FIN 45 will have a material impact on its financial statements. In December 2002 the FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation – Transition and Disclosure”, SFAS 148 amended the implementation provisions of SFAS 123 and required changes in disclosures in financial statements. The provisions of SFAS 148 were applicable for years ending after December 15, 2002 except for certain quarterly disclosures, which were applicable for interim periods beginning after December 15, 2002. The Company has not changed its method of accounting for stock-based compensation and, therefore, is subject only to the revised disclosure provisions of SFAS 148. Such disclosures have been included in these financial statements and quarterly disclosures will be provided commencing in the first quarter of 2003. In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities (“FIN 46”). FIN 46 establishes accounting and disclosure requirements for ownership interests in entities that have certain financial or ownership characteristics (sometimes known as Special Purpose Entities). FIN 46 is applicable for variable interest entities created after January 31, 2003 and becomes effective in the first fiscal year or interim accounting period beginning after June 15, 2003 for variable interest entities created before February 1, 2003. The Partnership does not anticipate that the provisions of FIN 46 will have a material impact on its financial statements.

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3. ACQUISITIONS Buckeye Terminals, LLC On June 30, 2000, a subsidiary of the Partnership acquired six petroleum products terminals from Agway Energy Products LLC (“Agway”) for a total purchase price of $19,000,000. Additional costs incurred in connection with the acquisition for gasoline and diesel fuel additives and closing adjustments amounted to $1,693,000. The terminals are operated under the name of Buckeye Terminals, LLC. The terminals are located in Brewerton, Geneva, Marcy, Rochester and Vestal, New York and Macungie, Pennsylvania. The terminals have an aggregate capacity of approximately 1.8 million barrels. The allocated fair value of assets acquired is summarized as follows:

Fuel additive inventory .................................................. $ 121,000Property, plant and equipment ........................................ 7,964,000Goodwill ......................................................................... 12,608,000 Total.............................................................................. $ 20,693,000

Norco Pipe Line Company, LLC

On July 31, 2001, a subsidiary of the Partnership acquired a petroleum products pipeline system and related terminals from affiliates of TransMontaigne Inc. for a total purchase price of $61,750,000. Additional costs incurred in connection with the acquisition amounted to $533,000. The assets included a 482-mile refined petroleum products pipeline that runs from Hartsdale, Indiana west to Fort Madison, Iowa and east to Toledo, Ohio, with an 11-mile pipeline connection between major storage terminals in Hartsdale and East Chicago, Indiana. The assets also included 3.2 million barrels of pipeline storage and trans-shipment facilities in Hartsdale and East Chicago, Indiana and Toledo, Ohio; and four petroleum products terminals located in Bryan, Ohio; South Bend and Indianapolis, Indiana; and Peoria, Illinois. The pipeline system is operated under the name of Norco Pipe Line Co., LLC. The terminal assets became part of Buckeye Terminals, LLC’s operations. The pipeline system and related terminals are collectively referred to as the “Norco Assets” or “Norco Operations”. The allocated fair value of assets acquired is summarized as follows:

Pipe inventory ................................................................ $ 688,000Property, plant and equipment ........................................ 61,595,000 Total.............................................................................. $ 62,283,000

Pro forma results of operations for the Partnership, assuming the acquisition of the Agway assets and the Norco

Operations’ assets had been acquired at the beginning of 2000, are as follows:

(Unaudited) Twelve Months Ended

December 31, 2001 2000

(In thousands, except per Unit amounts)

Revenue .................................................................. $ 242,138 $ 227,281 Income from continuing operations ........................ $ 71,324 $ 69,966 Net income.............................................................. $ 71,324 $ 101,830 Earnings per Partnership Unit from continuing operations........................................................... $ 2.63 $ 2.59 Earnings per Partnership Unit................................. $ 2.63 $ 3.76

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The unaudited pro forma results have been prepared for comparative purposes only and do not purport to be indicative of the results of operations which actually would have resulted had the combinations been in effect at the beginning of each period presented, or of future results of operations of the entities. 4. SEGMENT INFORMATION

During 2000, the Partnership operated in two business segments, the transportation segment and the refining segment. Operations in the refining segment commenced on the acquisition of BRC in March, 1999 and ceased upon the sale of BRC in October, 2000. As a result of the sale of BRC, the refining segment is accounted for as a discontinued operation in the accompanying financial statements. The Partnership’s continuing operations consist solely of its transportation segment.

The transportation segment derives its revenues primarily from the transportation of refined petroleum products that it receives from refineries, connecting pipelines and marine terminals. Terminalling and storage operations are ancillary to the Partnership’s pipeline operations. Contract operations of third-party pipelines are similar to the operations of the Partnership’s pipelines except that the Partnership does not own the facilities being operated.

5. DISCONTINUED OPERATIONS On October 25, 2000, the Partnership sold BRC to Kinder Morgan Energy Partners, L.P. for $45,696,000 in cash. The sale resulted in a gain of $26,182,000 after provision of $4,217,000 for conditional consideration payable to ARG by the Partnership pursuant to the acquisition agreement entered into in March 1999. The conditional consideration was paid to ARG in January 2001. Proceeds from the sale were used to repay $26,000,000 of debt and for working capital purposes.

Results of BRC’s operations are reported as a discontinued operation for all periods presented in the accompanying financial statements. BRC operated as a subsidiary of the Partnership for the period of March 4, 1999 through October 25, 2000. Summarized operating results of BRC were as follows for the period indicated below:

January 1, 2000 through October 25, 2000

Refining revenue ........................................... $ 172,451

Operating income .......................................... $ 5,526

Net income .................................................... $ 5,682 The Partnership hedged a substantial portion of its exposure to inventory price fluctuations related to its BRC business with commodity futures contracts for the sale of gasoline and fuel oil. Losses related to commodity futures contracts included in earnings from discontinued operations in the year 2000 were $6.7 million. 6. CONTINGENCIES The Partnership and the Operating Partnerships in the ordinary course of business are involved in various claims and legal proceedings, some of which are covered in whole or in part by insurance. The General Partner is unable to predict the timing or outcome of these claims and proceedings. Although it is possible that one or more of these claims or proceedings, if adversely determined, could, depending on the relative amounts involved, have a material effect on the Partnership for a future period, the General Partner does not believe that their outcome will have a material effect on the Partnership’s consolidated financial condition or annual results of operations.

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Environmental In accordance with its accounting policy on environmental expenditures, the Partnership recorded operating expenses of $1.9 million, $2.2 million and $1.5 million for 2002, 2001 and 2000, respectively, which were related to the environment. Expenditures, both capital and operating, relating to environmental matters are expected to continue due to the Partnership’s commitment to maintain high environmental standards and to increasingly strict environmental laws and government enforcement policies. Various claims for the cost of cleaning up releases of hazardous substances and for damage to the environment resulting from the activities of the Operating Partnerships or their predecessors have been asserted and may be asserted in the future under various federal and state laws. The General Partner believes that the generation, handling and disposal of hazardous substances by the Operating Partnerships and their predecessors have been in material compliance with applicable environmental and regulatory requirements. The total potential remediation costs to be borne by the Operating Partnerships relating to these clean-up sites cannot be reasonably estimated and could be material. With respect to each site, however, the Operating Partnership involved is typically one of several or as many as several hundred potentially responsible parties that would share in the total costs of clean-up under the principle of joint and several liability. Although the Partnership has made a provision for certain legal expenses relating to these matters, the General Partner is unable to determine the timing or outcome of any pending proceedings or of any future claims and proceedings. 7. GOODWILL AND INTANGIBLE ASSETS Effective January 1, 2002, the Partnership adopted Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” which establishes financial accounting and reporting for acquired goodwill and other intangible assets. Under SFAS No. 142, goodwill and indefinite-lived intangible assets are no longer amortized but are reviewed at least annually for impairment. Intangible assets that have finite useful lives will continue to be amortized over their useful lives. SFAS No. 142 requires that goodwill be tested for impairment at least annually utilizing a two-step methodology. The initial step requires the Partnership to determine the fair value of each of its reporting units and compare it to the carrying value, including goodwill, of such reporting unit. If the fair value exceeds the carrying value, no impairment loss is recognized. However, a carrying value that exceeds its fair value may be an indication of impaired goodwill. The amount, if any, of the impairment would then be measured and an impairment loss would be recognized. The Partnership has completed the transitional impairment test required upon adoption of SFAS No. 142. The transitional test, which involved the use of estimates related to the fair market value of the business operations associated with the goodwill, did not result in an impairment loss. The Partnership will continue to evaluate its goodwill, at least annually, and will reflect the impairment of goodwill, if any, in operating income in the income statement.

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The following represents pro-forma information for 2001 and 2000 as if SFAS No. 142 had been adopted at the beginning of the year and that goodwill amortization had been eliminated. The impact on net income, and basic and diluted earnings per share for the periods indicated below are as follows:

(Unaudited) December 31,

2001 2000 (In thousands, except per Unit amounts)

Reported net income $ 69,402 $ 96,331 Adjustment for amortization of goodwill 832 461

Adjusted net income $ 70,234 $ 96,792

Reported basic earnings per Unit $ 2.56 $ 3.56 Adjustment for amortization of goodwill 0.03 0.02

Adjusted basic earnings per Unit $ 2.59 $ 3.58

Reported diluted earnings per Unit $ 2.55 $ 3.55 Adjustment for amortization of goodwill 0.03 0.02

Adjusted diluted earnings per Unit $ 2.58 $ 3.57

The Partnership’s amortizable intangible assets consist of pipeline rights-of-way and contracts. The contracts were acquired in connection with the acquisition of Buckeye Gulf Coast Pipe Lines, LLC in March 1999. At December 31, 2002, the gross carrying amount of the pipeline rights-of-way was $25,328,000 and accumulated amortization was $3,909,000. Pipeline rights-of-way are included in property, plant and equipment in the accompanying balance sheet. At December 31, 2002, the gross carrying amount of the contracts was $3,600,000 and accumulated amortization was $900,000. For the years 2002, 2001 and 2000, amortization expense related to amortizable intangible assets was $749,000, and $727,000 and $712,000 respectively. Aggregate amortization expense related to amortizable intangible assets is estimated to be $747,000 per year for each of the next five years. The Partnership’s only intangible asset not subject to amortization is goodwill that was recorded in connection with the acquisition of Buckeye Terminals, LLC in June 2000. The carrying amount of the goodwill was $11,355,000 at December 31, 2002. During the reporting periods 2001 and 2000, goodwill was amortized on a straight-line basis over a period of fifteen years. Goodwill amortization expense related to continuing operations was $832,000 and $420,000 in 2001 and 2000, respectively. Goodwill amortization expense included in income from discontinued operations was $41,000 in 2000. 8. PREPAID AND OTHER CURRENT ASSETS Prepaid and other current assets consist primarily of receivables from third parties for pipeline relocations and other work either completed or in-progress. Prepaid and other current assets also include prepaid insurance, prepaid taxes and other miscellaneous items.

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9. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consist of the following:

December 31, 2002 2001

(In thousands) Land............................................................................................................................. $16,993 $16,904 Rights-of-way.............................................................................................................. 25,328 25,402 Buildings and leasehold improvements ....................................................................... 37,112 36,294 Machinery, equipment and office furnishings ............................................................. 673,917 645,751 Construction in progress.............................................................................................. 57,186 25,017 810,536 749,368 Less accumulated depreciation.................................................................................... 83,086 78,929 Total ..................................................................................................................... $727,450 $670,439 Construction in progress at December 31, 2002 includes $36,793,000 related to a 90-mile crude butadiene pipeline. At December 31, 2002, the Partnership had received advances totaling $14,157,000 from two petrochemical companies involved in the project based on construction milestones. These advances are included in other non-current liabilities in the accompanying financial statements (see Note 13). As of March 2003, the pipeline was substantially complete and a subsidiary of BGC owns a 63 percent interest in the pipeline with the two petrochemical companies owning the remaining interest. Depreciation expense was $15,765,000, $14,232,000 and $12,548,000 for the years 2002, 2001 and 2000, respectively. Depreciation expense related to discontinued operations was $434,000 in 2000. 10. OTHER NON-CURRENT ASSETS Other non-current assets consist of the following: December 31, 2002 2001 (In thousands) Deferred charge (see Note 16)....................................................................................... $ 38,906 $ 43,604 Contracts acquired from acquisitions ............................................................................ 2,700 2,940 Investment in West Shore Pipe Line Company............................................................. 23,268 23,268 Other.............................................................................................................................. 8,650 8,223 Total........................................................................................................................... $ 73,524 $ 78,035 The $64.2 million market value of limited partnership units (“LP Units”) issued in connection with the restructuring of the ESOP in August 1997 (the “ESOP Restructuring”) was recorded as a deferred charge and is being amortized on the straight-line basis over 164 months (see Note 16). Amortization of the deferred charge related to the ESOP Restructuring was $4,698,000 in 2002, 2001 and 2000. Amortization expense related to the contracts acquired from acquisition was $240,000 in each of 2002 and 2001.

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11. ACCRUED AND OTHER CURRENT LIABILITIES Accrued and other current liabilities consist of the following:

December 31, 2002 2001

(In thousands) Taxes—other than income............................................................................................... $ 3,330 $ 4,727 Accrued charges due General Partner.............................................................................. 4,478 6,552 Environmental liabilities ................................................................................................. 2,637 3,148 Interest ............................................................................................................................. 1,345 1,447 Accrued operating power ................................................................................................ 856 1,091 Deposits ........................................................................................................................... 3 1,333 Accrued top-up reserve (see Note 16) ............................................................................. 1,295 1,295 Retainage......................................................................................................................... 1,236 34 Other................................................................................................................................ 7,508 5,258 Total ......................................................................................................................... $ 22,688 $ 24,885 12. LONG-TERM DEBT AND CREDIT FACILITIES Long-term debt consists of the following:

December 31, 2002 2001 (In thousands)

Senior Notes: 6.98% Series 1997A due December 16, 2024 (subject to $25.0 million annual sinking fund requirement commencing December 16, 2020) ...........................................

$ 125,000

$ 125,000

6.89% Series 1997B due December 16, 2024 (subject to $20.0 million annual sinking fund requirement commencing December 16, 2020) ...........................................

100,000

100,000

6.95% Series 1997C due December 16, 2024 (subject to $2.0 million annual sinking fund requirement commencing December 16, 2020) ...........................................

10,000

10,000

6.96% Series 1997D due December 16, 2024 (subject to $1.0 million annual sinking fund requirement commencing December 16, 2020) ...........................................

5,000

5,000

Credit Facility due September 5, 2006 (variable rates; average weighted rate at December 31, 2002 was 2.56% and at December 31, 2001 was 3.05%)................................................................

165,000

133,000

Total........................................................................................................... $ 405,000 $ 373,000 At December 31, 2002, a total of $165.0 million of debt was scheduled to mature in September 2006. A total of $240.0 million of debt is scheduled to mature in the period 2020 through 2024. The fair value of the Partnership’s debt is estimated to be $429 million and $372 million as of December 31, 2002 and 2001, respectively. The values at December 31, 2002 and 2001 were calculated using interest rates currently available to the Partnership for issuance of debt with similar terms and remaining maturities. In December 1997, Buckeye entered into an agreement to issue $240.0 million of Senior Notes (Series 1997A through 1997D) bearing interest ranging from 6.89 percent to 6.98 percent. The indenture, as amended in connection with the issuance of the Senior Notes (the “Indenture”), contains covenants that affect Buckeye, Laurel and Buckeye Pipe Line Company of Michigan, L.P. (the “Indenture Parties”). Generally, the Indenture (a) limits

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outstanding indebtedness of Buckeye based upon certain financial ratios of the Indenture Parties, (b) prohibits the Indenture Parties from creating or incurring certain liens on their property, (c) prohibits the Indenture Parties from disposing of property which is material to their operations, and (d) limits consolidation, merger and asset transfers of the Indenture Parties. At December 31, 2002, the Indenture Parties were in compliance with the covenants contained in the Senior Notes. During September and October 2001, the Partnership entered into a $277.5 million 5-year Revolving Credit Agreement and a $92.5 million 364-day Revolving Credit Agreement (the “Credit Facilities”) with a syndicate of banks led by SunTrust Bank. In September 2002 the Partnership entered into a new 364-day Agreement with another syndicate of banks also led by SunTrust Bank and reduced the maximum amount borrowable to $85.0 million. Certain covenants in both agreements were amended to eliminate the requirement of at least one investment grade rating from either Standard and Poor’s or Moody’s Investor Services. Together, these Credit Facilities permit borrowings of up to $362.5 million subject to certain limitations contained in the Credit Facilities. Borrowings bear interest at Sun Trust Bank’s base rate or at a rate based on the London Interbank Offered Rate (“LIBOR”) at the option of the Partnership. At December 31, 2002, the Partnership had borrowed $165 million under the 5-year Revolving Credit Agreement at an average weighted LIBOR pricing option rate of 2.56 percent.

The Credit Facilities contain certain covenants that affect the Partnership. Generally, the Credit Facilities (a) limit outstanding indebtedness of the Partnership based upon certain financial ratios contained in the Credit Facilities (b) prohibit the Partnership from creating or incurring certain liens on its property, (c) prohibit the Partnership from disposing of property which is material to its operations and (d) limit consolidations, mergers and asset transfers by the Partnership. At December 31, 2002, the Partnership was in compliance with the covenants contained in the Credit Facilities. Concurrent with the 2001 execution of the Credit Facilities, Buckeye repaid all borrowings outstanding under its then existing $100 million Credit Agreement with First Union National Bank (“First Union”) and its $30 million Loan Agreement with First Union. Those agreements were terminated with the repayment of the borrowings. 13. OTHER NON-CURRENT LIABILITIES Other non-current liabilities consist of the following:

December 31, 2002 2001 (In thousands)

Accrued employee benefit liabilities (see Note 14)....................................................... $ 36,891 $ 36,188 Accrued environmental liabilities.................................................................................. 4,857 6,125 Accrued top-up reserve (see Note 16) ........................................................................... 3,321 3,484 Advances related to pipeline project (see Note 9) ......................................................... 14,157 - Other.............................................................................................................................. 265 259 Total ....................................................................................................................... $ 59,491 $ 46,056 14. PENSIONS AND OTHER POSTRETIREMENT BENEFITS Services Company sponsors a retirement income guarantee plan (a defined benefit plan) which generally guarantees employees hired before January 1, 1986, a retirement benefit at least equal to the benefit they would have received under a previously terminated defined benefit plan. Services Company’s policy is to fund amounts necessary to at least meet the minimum funding requirements of ERISA. Services Company also provides postretirement health care and life insurance benefits to certain of its retirees. To be eligible for these benefits an employee had to be hired prior to January 1, 1991 and meet certain service requirements. Services Company does not pre-fund this postretirement benefit obligation.

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A reconciliation of the beginning and ending balances of the benefit obligations under the retirement income guarantee plan and the postretirement health care and life insurance plan is as follows:

Postretirement Pension Benefits Benefits 2002 2001 2002 2001 (In thousands)

Change in benefit obligation Benefit obligation at beginning of year ................. $ 11,097 $ 9,921 $ 32,718 $ 28,037 Service cost ........................................................... 539 641 654 486 Interest cost ........................................................... 838 941 2,358 2,181 Actuarial loss ......................................................... 5,432 3,269 5,014 3,765 Change in assumptions........................................... (969) (386) - - Amendment............................................................ (1) 394 (2,218) - - Benefit payments ................................................... (861) (1,071) (1,671) (1,751) Benefit obligation at end of year ........................... $ 16,470 $ 11,097 $ 39,073 $ 32,718 ______________ (1) During 2001, the retirement income guaranty plan was amended to (i) exclude bonus payments,

beginning with bonuses payable in 2003 and thereafter, from the definition of compensation used to calculate benefits under the plan, and (ii) provide that the annuity equivalent of the 5 percent company contribution, used as an offset to benefits payable under the plan, will be calculated using a 7.5 percent discount rate in lieu of the 30-year Treasury Bond rate. The 7.5 percent discount rate in lieu of the 30-year Treasury Bond rate was lowered to 7.25 percent in 2002.

A reconciliation of the beginning and ending balances of the fair value of plan assets under the retirement income guarantee plan and the postretirement health care and life insurance plan is as follows:

Postretirement Pension Benefits Benefits 2002 2001 2002 2001 (In thousands)

Change in plan assets Fair value of plan assets at beginning of year ......... $ 6,855 $ 7,293 $ - $ - Actuarial return on plan assets ................................ (206) 300 - - Employer contribution ............................................ 659 333 1,671 1,751 Benefits paid ............................................................ (861) (1,071) (1,671) (1,751) Fair value of plan assets at end of year ................... $ 6,447 $ 6,855 $ - $ -

Funded status .......................................................... $ (10,023) $ (4,242) $ (39,073) $ (32,718) Unrecognized prior service benefit .......................... (3,907) (2,671) (579) (1,159) Unrecognized actuarial loss .................................... 8,578 1,694 7,550 2,573 Unrecognized net asset at transition ........................ (139) (303) - - Accrued benefit cost ................................................ $ (5,491) $ (5,522) $ (32,102) $ (31,304)

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The weighted average assumptions used in accounting for the retirement income guarantee plan and the postretirement health care and life insurance plan were as follows:

Pension Benefits Postretirement

Benefits 2002 2001 2002 2001 Weighted-average assumptions as of December 31 Discount rate ............................................................. 6.50% 7.25% 6.50% 7.25% Expected return on plan assets .................................. 8.50% 8.50% N/A N/A Rate of compensation increase .................................. 4.00% 4.50% N/A N/A The assumed rate of cost increase in the postretirement health care and life insurance plan in 2002 was 10 percent for both non-Medicare eligible and Medicare eligible retirees. The assumed annual rates of cost increase decline each year through 2009 to a rate of 4.75 percent, and remain at 4.75 percent thereafter for both non-Medicare eligible and Medicare eligible retirees. Assumed healthcare cost trend rates have a significant effect on the amounts reported for the healthcare plans. The effect of a 1 percent change in the health care cost trend rate for each future year would have had the following effects on 2002 results: 1-Percentage

Point Increase 1-Percentage

Point Decrease (In thousands) Effect on total service cost and interest cost components $ 540 $ (454) Effect on postretirement benefit obligation ..................... $ 6,068 $(5,229) The components of the net periodic benefit cost recognized for the retirement income guarantee plan and the postretirement health care and life insurance plan were as follows:

Pension Benefits Postretirement Benefits 2002 2001 2000 2002 2000 2000 (In thousands)

Components of net periodic benefit cost Service cost .......................................................... $ 539 $ 641 $ 519 $ 654 $ 486 $ 518 Interest cost .......................................................... 838 941 726 2,358 2,181 1,983 Expected return on plan assets ............................. (558) (578) (676) - - - Amortization of unrecognized transition asset..... (163) (160) (160) - - - Amortization of prior service benefit ................... (572) (116) (96) (580) (580) (580) Amortization of unrecognized (gains)/losses ....... 382 70 (149) 37 34 21 Net periodic benefit cost ...................................... $ 466 $ 798 $ 164 $ 2,469 $ 2,121 $ 1,942 Services Company sponsors a retirement and savings plan (the “Retirement Plan”) through which it provides retirement benefits to substantially all of its regular full-time employees, except those covered by certain labor contracts. Norco, BGC and BT also participate in the Retirement Plan and substantially all of their regular full-time employees are covered by the Retirement Plan. Pursuant to the terms of the retirement plan, each participating company contributes 5 percent of each eligible employee’s covered salary to an employee’s separate account maintained in the Retirement Plan. In addition, Norco, BGC and BT make a matching contribution of up to 6 percent of an employee’s contributions to the Retirement Plan. Total costs of the Retirement Plan were approximately $2,222,000 in 2002, $2,024,000 in 2001 and $1,752,000 in 2000.

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Services Company also participates in a multi-employer retirement income plan that provides benefits to employees covered by certain labor contracts. Pension expense for the plan was $146,000, $170,000 and $119,000 for 2002, 2001 and 2000, respectively. In addition, Services Company contributes to a multi-employer postretirement benefit plan that provides health care and life insurance benefits to employees covered by certain labor contracts. The cost of providing these benefits was approximately $101,000, $98,000 and $95,000 for 2002, 2001 and 2000, respectively. 15. UNIT OPTION AND DISTRIBUTION EQUIVALENT PLAN

The Partnership has a Unit Option and Distribution Equivalent Plan (the “Option Plan”), which was approved by the Board of Directors of the General Partner on April 25, 1991 and by holders of the LP Units on October 22, 1991. The Option Plan was amended and restated on July 14, 1998. On April 24, 2002, the Board approved an Amended and Restated Unit Option and Distribution Equivalent Plan to extend the term thereof for an additional ten years and to make certain administrative changes in the Plan, the Unit Option Loan Program of the General Partner and related documents. The Option Plan authorizes the granting of options (the “Options”) to acquire LP Units to selected key employees (the “Optionees”) not to exceed 720,000 LP Units in the aggregate. The price at which each LP Unit may be purchased pursuant to an Option granted under the Option Plan is generally equal to the market value on the date of the grant. Options granted prior to 1998 were granted with a feature that allowed Optionees to apply accrued credit balances (the “Distribution Equivalents”) as an adjustment to the aggregate purchase price of such Options. The Distribution Equivalents are an amount equal to (i) the Partnership’s per LP Unit regular quarterly distribution, multiplied by (ii) the number of LP Units subject to such Options that have not vested. With respect to options granted after 1997, Distribution Equivalents are paid as independent cash bonuses on the date Options vest dependent upon the percentage attainment of 3-year distributable cash flow targets. Vesting in the Options is determined by the number of anniversaries the Optionee has remained in the employ of Services Company or affiliates of the Partnership following the date of the grant of the Option. Options granted prior to 1998 vested in varying amounts beginning generally three years after the date of grant. Options granted after 1997 vest completely in three years after the date of the grant. Options granted after 1997 are exercisable for a period of seven years following the date on which they vest. Options granted prior to 1998 are exercisable for a period of five years following the date on which they vest. The Partnership recorded compensation expense related to the Option Plan of $1,000 in 2002, $7,000 in 2001 and $20,000 in 2000. Compensation and benefit costs of executive officers were not charged to the Partnership after August 12, 1997 (see Note 18).

The fair value of each option is estimated on the date of grant using the Black-Scholes option-pricing model. A portion of each option granted prior to 1998 vests after three, four and five years following the date of the grant. The assumptions used for options granted in 2002, 2001 and 2000 are indicated below.

Risk-free Interest Rate Expected Life (Years) Year of Dividend Vesting Period Vesting Period

Option Grant Yield Volatility 3 Years 3 Years 2002 6.8% 31.8% 3.6% 3.50

2001 7.4% 28.7% 4.7% 3.50

2000 9.3% 19.4% 6.5% 3.50

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A summary of the changes in the LP Unit options outstanding under the Option Plan as of December 31, 2002, 2001 and 2000 is as follows:

2002 2001 2000

Units Weighted Units Weighted Units Weighted

Under Average Under Average Under Average

Option Exercise Price Option Exercise Price Option Exercise Price Outstanding at beginning of year ..... 163,100 $25.17 199,740 $20.17 204,040 $17.86 Granted ............................................. 47,400 36.56 42,600 33.90 45,900 25.75 Exercised .......................................... (18,300) 23.28 (73,940) 16.20 (50,200) 14.09 Forfeitures ........................................ (3,000) 29.38 (5,300) 27.45 - - Outstanding at end of year ............... 189,200 28.10 163,100 25.17 199,740 20.17

Options exercisable at year-end ....... 65,300 45,700 78,740 Weighted average fair value of options granted during the year......

$5.65

$4.72

$2.03

The following table summarizes information relating to LP Unit options outstanding under the Option Plan at December 31, 2002: Options Outstanding Options Exercisable

Options Weighted Average Weighted Options Weighted Range of Outstanding Remaining Average Exercisable Average Exercise Prices at 12/31/02 Contractual Life Exercise Price at 12/31/02 Exercise Price $ 8.00 to $10.00 4,000 2.1 Years $ 8.30 4,000 $ 8.30 $10.01 to $15.00 21,400 1.9 Years 12.77 21,400 12.77 $15.01 to $20.00 13,000 2.1 Years 15.80 13,000 15.80 $20.01 to $30.00 61,800 6.8 Years 26.89 25,400 28.52 $30.01 to $35.00 89,000 8.7 Years 35.32 1,500 33.90 Total 189,200 6.7 Years 28.10 65,300 19.71

At December 31, 2002, there were 165,100 LP Units available for future grants under the Option Plan. The Partnership also offers a unit option loan program whereby Optionees may borrow, at market rates, up to 95 percent of the purchase price of the LP Units and up to 100 percent of the applicable income tax withholding obligation in connection with such exercise. At December 31, 2002, 10 employees had outstanding loans under the unit option loan program. The aggregate borrowings outstanding at December 31, 2002 and 2001 were $1,430,000 and $1,408,000, respectively, of which $913,000 and $995,000, respectively, were related to the purchase price of the LP Units. 16. EMPLOYEE STOCK OWNERSHIP PLAN Services Company provides an employee stock ownership plan (the “ESOP”) to substantially all of its regular full-time employees, except those covered by certain labor contracts. The ESOP owns all of the outstanding common stock of Services Company. At December 31, 2002, the ESOP was directly obligated to a third-party lender for $47.5 million of 7.24 percent notes ( the “ESOP Notes”). The ESOP Notes are secured by Services Company common stock and are guaranteed by Glenmoor and certain of its affiliates. The proceeds from the issuance of the ESOP Notes were used to purchase Services Company common stock. Services Company stock is released to employee accounts in the proportion that current payments of principal and interest on the ESOP Notes bear to the total of all principal and interest payments due under the ESOP Notes. Individual employees are allocated shares based upon the ratio of their eligible compensation to total eligible compensation. Eligible compensation generally includes base salary, overtime payments and certain bonuses. Services Company stock allocated to employees receives stock dividends in lieu of cash, while cash dividends are used to pay principal and interest on the ESOP Notes.

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The Partnership contributed 2,573,146 LP Units to Services Company in August 1997 in exchange for the elimination of the Partnership’s obligation to reimburse BMC for certain executive compensation costs, a reduction of the incentive compensation paid by the Partnership to BMC under the existing incentive compensation agreement, and other changes that made the ESOP a less expensive fringe benefit for the Partnership. Funding for the ESOP Notes is provided by distributions that Services Company receives on the LP Units that it owns and from cash payments from the Partnership, as required to cover any shortfall between the distributions that Services Company receives on the LP Units that it owns and amounts currently due under the ESOP Notes (the “top-up reserve”). The Partnership will also incur ESOP-related costs for taxes associated with the sale and annual taxable income of the LP Units and for routine administrative costs. Total ESOP related costs charged to earnings were $1,162,000 in 2002 and $1,100,000 in each of 2001 and 2000. 17. LEASES AND COMMITMENTS The Operating Partnerships lease certain land and rights-of-way. Minimum future lease payments for these leases as of December 31, 2002 are approximately $3.4 million for each of the next five years. Substantially all of these lease payments can be canceled at any time should they not be required for operations. The General Partner leases space in an office building and certain copying equipment and charges these costs to the Operating Partnerships. Buckeye leases certain computing equipment and automobiles. Future minimum lease payments under these noncancelable operating leases at December 31, 2002 were as follows: $734,000 for 2003, $649,000 for 2004, $657,000 for 2005, $483,000 for 2006, $59,000 for 2007 and none thereafter. Buckeye entered into an energy services agreement for certain main line pumping equipment and the natural gas requirements to fuel this equipment at its Linden, New Jersey facility. Under the energy services agreement, which is designed to reduce power costs at the Linden facility, Buckeye is required to pay a minimum of $1,743,000 annually over the next nine years. This minimum payment is based on an annual minimum usage requirement of the natural gas engines at the rate of $0.049 per kilowatt hour equivalent. In addition to the annual usage requirement, Buckeye is subject to minimum usage requirements during peak and off-peak periods. Buckeye’s use of the natural gas engines has exceeded the minimum requirement in 2000, 2001 and 2002. Rent expense under operating leases was $7,285,000, $7,700,000, and $8,855,000 for 2002, 2001 and 2000, respectively. Included in rent expense for operating leases is $1,191,000 related to discontinued operations for 2000. 18. RELATED PARTY TRANSACTIONS The Partnership and the Operating Partnerships are managed by the General Partner. Under certain partnership agreements and management agreements, BMC, the General Partner, Services Company and certain related parties are entitled to reimbursement of substantially all direct and indirect costs related to the business activities of the Partnership and the Operating Partnerships. On May 1, 2002, an Amended and Restated Exchange Agreement (the “Amended Exchange Agreement”), among the Partnership, the Operating Partnerships, the General Partner, BMC and Glenmoor was approved in accordance with the terms of the Partnership’s Limited Partnership Agreement. The Amended Exchange Agreement, which is designed to better align the interests of the General Partner and the Partnership, was approved by the Board of Directors of Buckeye Pipe Line Company based upon a recommendation of a special committee of disinterested directors of the Board. The principal change reflected in the Amended Exchange Agreement was the elimination of the forfeiture payment provision contained in the original Exchange Agreement. The Amended Exchange Agreement also includes certain definitional and other minor changes.

As a condition of entering into the Amended Exchange Agreement, Glenmoor and the Partnership entered into an Acknowledgement and Agreement under which Glenmoor acknowledged and agreed that any tax liabilities of Glenmoor resulting from the Amended Exchange Agreement were the responsibility of Glenmoor and its subsidiaries and not the Partnership and that any funds borrowed by Glenmoor from third party lenders to pay those tax liabilities would be the responsibility of Glenmoor and its subsidiaries and not the Partnership.

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Services Company employs a significant portion of the employees that work for the Operating Partnerships. Services Company entered into a Services Agreement with BMC and the General Partner in August 1997 to provide services to the Partnership and the Operating Partnerships through March 2011. Services Company is reimbursed by BMC or the General Partner for its direct and indirect expenses, other than with respect to certain executive compensation. BMC and the General Partner are then reimbursed by the Partnership and the Operating Partnerships. Costs reimbursed to BMC, the General Partner or Services Company by the Partnership and the Operating Partnerships totaled $60.5 million, $58.4 million and $53.6 million in 2002, 2001 and 2000, respectively. The reimbursable costs include insurance, general and administrative costs, compensation and benefits payable to employees of Services Company, tax information and reporting costs, legal and audit fees and an allocable portion of overhead expenses. Services Company, which is beneficially owned by the ESOP, owns 2,465,320 LP Units (approximately 9.2 percent of the LP Units outstanding). Distributions received by Services Company on such LP Units are used to fund obligations of the ESOP. Distributions paid to Services Company totaled $6,188,000, $6,121,000 and $6,050,000 in 2002, 2001 and 2000, respectively. In addition, the Partnership recorded ESOP-related costs of $1,162,000, $1,100,000 and $1,099,000 in 2002, 2001 and 2000, respectively (see Note 16). Glenmoor and BMC are entitled to receive an annual management fee for certain management functions they provide to the General Partner pursuant to a Management Agreement among Glenmoor, BMC and the General Partner. The disinterested directors of the General Partner approve the amount on a periodic basis. The management fee includes a Senior Administrative Charge of not less than $975,000 and reimbursement for certain costs and expenses. Amounts paid to Glenmoor and BMC in 2002 amounted to $1,906,000, including $975,000 for the Senior Administrative Charge and $931,000 of reimbursed expenses. Amounts paid to Glenmoor and BMC in each of the years 2001 and 2000 for management fees were $1,984,000 and $2,220,000, respectively, including $975,000 for the Senior Administrative Charge and $1,009,000 and $1,245,000, respectively of reimbursed expenses. The Senior Administration charge and reimbursed expenses are charged to the Partnership. The General Partner receives incentive compensation payments from the Partnership pursuant to an incentive compensation agreement based upon the level of quarterly cash distributions paid per LP Unit. Incentive compensation payments totaled $10,838,000, $10,272,000 and $9,698,000 and in 2002, 2001 and 2000, respectively. The incentive compensation payments are included in “minority interests and other” expense on the Consolidated Statements of Income. In April 2001, in order to better align the interests of the Partnership and the General Partner, the Partnership and the General Partner entered into the Second Amended and Restated Incentive Compensation Agreement (“Incentive Compensation Agreement”). The principal change reflected in the Incentive Compensation Agreement was the elimination prospectively of a cap on aggregate incentive compensation payments to the General Partner effective December 31, 2005, or earlier if distributions on LP Units equal or exceed $.6375 per LP Unit for four consecutive quarterly periods ($2.55 annually). The amendment was approved in accordance with the Partnership Agreement by the Board of Directors of the General Partner based upon a recommendation of a special committee of disinterested members of the Board.

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19. PARTNERS’ CAPITAL Changes in partners’ capital for the years ended December 31, 2000, 2001, and 2002 were as follows:

General Partner

Limited Partners

Receivable from Exercise

of Options

Total (In thousands, except for Units)

Partners’ capital at January 1, 2000........................................ $ 2,548 $ 314,441 $ - $ 316,989 Net income ............................................................................. 868 95,463 - 96,331 Distributions........................................................................... (585) (64,366) - (64,951) Exercise of unit options.......................................................... - 1,013 - 1,013 Partners’ capital at December 31, 2000.................................. 2,831 346,551 - 349,382

Net income ............................................................................. 601 68,801 - 69,402 Distributions........................................................................... (598) (65,866) - (66,464) Exercise of unit options.......................................................... - 1,571 - 1,571 Receivable from exercise of options ...................................... - - (995) (995) Partners’ capital December 31, 2001...................................... 2,834 351,057 (995) 352,896

Net income ............................................................................. 646 71,256 71,902 Distributions........................................................................... (610) (67,322) (67,932) Exercise of unit options.......................................................... - 484 484 Net change in receivable from exercise of options................. - - 82 82 Partners’ capital December 31, 2002...................................... $ 2,870 $ 355,475 $ (913) $ 357,432 Units outstanding at January 1, 2000 ..................................... 243,914 26,796,406 27,040,320 Units issued pursuant to the unit option and distribution equivalent plan and capital contributions ........

-

50,200

50,200

Units outstanding at December 31, 2000................................ 243,914 26,846,606 27,090,520 Units issued pursuant to the unit option and distribution equivalent plan....................................................................

-

73,940

73,940

Units outstanding at December 31, 2001 243,914 26,920,546 27,164,460 Units issued pursuant to the unit option and distribution equivalent plan....................................................................

-

18,300

18,300

Units outstanding at December 31, 2002................................ 243,914 26,938,846 27,182,760

Net income per unit was calculated using the weighted average outstanding LP Units of 27,172,752 in 2002, 27,131,286 in 2001, and 27,062,809 in 2000. The Partnership Agreement provides that without prior approval of limited partners of the Partnership holding an aggregate of at least two-thirds of the outstanding LP Units, the Partnership cannot issue any additional LP Units of a class or series having preferences or other special or senior rights over the LP Units. The receivable from the exercise of options is due from Services Company for notes issued under the unit option loan program (see Note 15). The notes are full recourse promissory notes due from Optionees, bearing market rates of interest. On February 28, 2003, the Partnership sold 1,750,000 LP units in an underwritten public offering at a price of $36.01 per LP unit. Proceeds to the Partnership, net of underwriters’ discount of $1.62 per LP unit and estimated offering expenses, were approximately $59.7 million. 20. CASH DISTRIBUTIONS The Partnership makes quarterly cash distributions to Unitholders of substantially all of its available cash, generally defined as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as the General Partner deems appropriate. In 2002, quarterly

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distributions of $0.625 per GP and LP Unit were paid in February, May, August and November. In 2001, quarterly distributions of $0.60 per GP and LP Unit were paid in February and May, and $0.625 per GP and LP Unit were paid in August and November. In 2000, quarterly distributions of $0.60 per GP and LP Unit were paid in February, May, August and November. All such distributions were paid on the then outstanding GP and LP Units. Cash distributions aggregated $67,932,000 in 2002, $66,464,000 in 2001 and $64,951,000 in 2000. 21. QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data for 2002 and 2001 are set forth below. Quarterly results were influenced by seasonal and other factors inherent in the Partnership’s business. 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total

2002 2001 2002 2001 2002 2001 2002 2001 2002 2001

(In thousands, except per unit amounts)

Transportation revenue ......................... $56,891 $54,417 $61,061 $56,867 $63,582 $58,650 $65,811 $62,463 $247,345 $232,397Operating income.................................. 22,047 21,853 24,664 23,012 27,298 24,570 28,353 28,896 102,362 98,331Net income ............................................ 14,425 14,923 16,509 16,050 20,034 16,706 20,934 21,723 71,902 69,402Earnings per Partnership Unit: Net income per Unit............................ 0.53 0.55 0.61 0.59 0.74 0.62 0.77 0.80 2.65 2.56Earnings per Partnership Unit: assuming dilution:

Net income per Unit............................ 0.53 0.55 0.61 0.59 0.74 0.61 0.76 0.80 2.64 2.55 22. EARNINGS PER UNIT

The following is a reconciliation of basic and dilutive income from continuing operations per LP Unit for the years ended December 31, 2002, 2001 and 2000: 2002 2001 2000

Income (Numer-ator)

Units (Denom-inator)

Per Unit Amt.

Income (Numer-ator)

Units (Denom-inator)

Per Unit Amt.

Income (Numer-

ator)

Units (Denom-inator)

Per Unit Amt.

Income from continuing operations ........ $71,902 $69,402 $64,467 Basic earnings per Partnership Unit........ 71,902 27,173 $2.65 69,402 27,131 $2.56 64,467 27,063 $2.38

Effect of dilutive securities – options ..... - 55 - 62 - 75 Diluted earnings per Partnership Unit..... $71,902 27,228 $2.64 $69,402 27,193 $2.55 $64,467 27,138 $2.38

Options reported as dilutive securities are related to unexercised options outstanding under the Option Plan

(see Note 15).

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable.

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PART III

Item 10. Directors and Executive Officers of the Registrant The Partnership does not have directors or officers. The executive officers of the General Partner perform all management functions for the Partnership and the Operating Partnerships in their capacities as officers and directors of the General Partner and Services Company. Directors and officers of the General Partner are selected by BMC. See “Certain Relationships and Related Transactions.” Directors of the General Partner Set forth below is certain information concerning the directors of the General Partner. Name, Age and Present Position with General Partner

Business Experience During Past Five Years

Alfred W. Martinelli, 75 Chairman of the Board*

Mr. Martinelli has been Chairman of the Board of the General Partner and BMC since April 1987. He was Chief Executive Officer of the General Partner and BMC from April 1987 to September 2000. Mr. Martinelli has been a Director of the General Partner and BMC since October 1986.

William H. Shea, Jr., 48 President and Chief Executive Officer and Director*

Mr. Shea was named President and Chief Executive Officer and a director of the General Partner on September 27, 2000. He served as President and Chief Operating Officer of the General Partner from July 1998 to September 2000. Mr. Shea had been named Executive Vice President of the General Partner in September 1997 and previously served as Vice President of Marketing and Business Development of the General Partner from March 1996 to September 1997. He is the son-in-law of Mr. Alfred W. Martinelli.

Brian F. Billings, 64 Director

Mr. Billings became a director of the General Partner on December 31, 1998. Mr. Billings was a director of BMC from October 1986 to December 1998.

Edward F. Kosnik, 58 Director

Mr. Kosnik became a director of the General Partner on December 31, 1998. He was a director of BMC from October 1986 to December 1998. Mr. Kosnik was President and Chief Executive Officer of Berwind Corporation, a diversified industrial real estate and financial services company, from December 1999 until February 2001 and was President and Chief Operating Officer of Berwind Corporation from June 1997 to December 1999. He was Senior Executive Vice President and Chief Operating Officer of Alexander & Alexander Services, Inc. from May 1996 until January 1997.

Jonathan O’Herron, 73 Director

Mr. O’Herron became a director of the General Partner on December 31, 1998. Mr. O’Herron was a director of BMC from September 1997 to December 1998. He has been Managing Director of Lazard Freres & Company, LLC for more than five years.

55

Name, Age and Present Position with General Partner

Business Experience During Past Five Years

Joseph A. LaSala, Jr., 48 Director

Mr. LaSala became a director of the General Partner on April 23, 2001. He has served as Vice President, General Counsel and Secretary of Novell, Inc. since July 11, 2001. Mr. LaSala served as Vice President, General Counsel and Secretary of Cambridge Technology Partners from March 2000 to July 2001. He had been Vice President, General Counsel and Secretary of Union Pacific Resources, Inc. from January 1997 to February 2000.

David J. Martinelli, 42 Senior Vice President— Corporate Development and Treasurer and Director*

Mr. Martinelli became a director of the General Partner on September 27, 2000. He was named Senior Vice President – Corporate Development and Treasurer of the General Partner in December 1999. Mr. Martinelli served as Senior Vice President and Treasurer of the General Partner from July 1998 to December 1999 and previously served as Vice President and Treasurer of the General Partner from June 1996. He is the son of Mr. Alfred W. Martinelli.

Frank S. Sowinski, 46 Director

Mr. Sowinski became a director of the General Partner on February 22, 2001. He served as Executive Vice President and Chief Financial Officer of PWC Consulting, a systems integrator company, from May 2002 to October 2002. Mr. Sowinski was a Senior Vice President and Chief Financial Officer of the Dun & Bradstreet Corporation from October 2000 to April 2001. He served as President of the Dun & Bradstreet operating company from September 1999 to October 2000. Mr. Sowinski had been Senior Vice President and Chief Financial Officer of the Dun & Bradstreet Corporation from November 1996 to September 1999.

Ernest R. Varalli, 72 Director*

Mr. Varalli has been a director of the General Partner and BMC since July 1987.

* Also a director of Services Company. The General Partner has an Audit Committee, which currently consists of four directors: Brian F. Billings, Edward F. Kosnik, Jonathan O’Herron and Frank S. Sowinski. Messrs. Billings, Kosnik, O'Herron and Sowinski are neither officers nor employees of the General Partner or any of its affiliates. In addition, the General Partner has a Finance Committee, which currently consists of three directors: Edward F. Kosnik, Jonathan O’Herron and Ernest R. Varalli. The Finance Committee provides oversight and advice with respect to the capital structure of the Partnership.

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Executive Officers of the General Partner Set forth below is certain information concerning the executive officers of the General Partner who also serve in similar positions in BMC and Services Company.

Name, Age and Present Position

Business Experience During Past Five Years

Stephen C. Muther, 53 Senior Vice President— Administration, General Counsel and Secretary

Mr. Muther has been Senior Vice President – Administration, General Counsel and Secretary of the General Partner for more than six years.

Steven C. Ramsey, 48 Senior Vice President—Finance and Chief Financial Officer

Mr. Ramsey has been Senior Vice President – Finance and Chief Financial Officer of the General Partner for more than six years.

Section 16 (a) Beneficial Ownership Reporting Compliance Pursuant to Section 16 (a) of the Exchange Act, the Company’s executive officers and directors, and persons beneficially owning more than 10 percent of the Partnership’s LP Units, are required to file with the Commission reports of their initial ownership and changes in ownership of common shares. The Company believes that for 2002, its executive officers and directors who were required to file reports under Section 16 (a) complied with such requirements in all material respects. Item 11. Executive Compensation Director Compensation The fee schedule for directors of the General Partner is as follows: annual fee, $25,000; attendance fee for each Board of Directors meeting, $1,000; and attendance fee for each committee meeting, $750. Messrs. Alfred and David Martinelli, Shea, and Varalli do not receive any fees as directors. Directors’ fees paid by the General Partner in 2002 to its directors amounted to $234,000. The directors’ fees were reimbursed by the Partnership. Members of the Board of Directors of BMC and Services Company are not separately compensated for their services as directors. Executive Compensation As part of a restructuring of the ESOP in 1997, the Partnership and the Operating Partnerships were permanently released from their obligation to reimburse the General Partner for certain compensation and fringe benefit costs for executive level duties performed by the General Partner with respect to operations, finance, legal, marketing and business development, and treasury, as well as the President of the General Partner.

Executive Officer Severance Agreements BMC, Service Company and Glenmoor have entered into severance agreements with Stephen C. Muther, Senior Vice President – Administration, General Counsel and Secretary and Steven C. Ramsey, Senior Vice President – Finance and Chief Financial Officer. The severance agreements provide for 1.5 times the officer’s annual base salary and incentive compensation as of May 1997 (the “Severance Compensation Amount”) upon termination of such individual’s employment without “cause” under certain circumstances not involving a “change of control” of the Partnership, and 2.99 times such individual’s Severance Compensation Amount (subject to certain limitations) following a “change of control.” For purposes of the severance agreements, a “change of control” is defined as the acquisition (other than by the General Partner and its affiliates) of 80 percent or more of the LP Units of the Partnership, 51 percent or more of the general partnership interests owned by the General Partner or 50 percent or more of the voting equity interest of the Partnership and the General Partner on a combined basis. Certain costs incurred under the severance agreements are to be reimbursed by the Partnership.

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Equity Compensation Plan Information The following table sets forth information as of December 31, 2002 with respect to compensation plans under which equity securities of the Partnership are authorized for issuance.

Plan category

Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)

Weighted-average exercise price of outstanding options, warrants and rights (b)

Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)

Equity compensation plans approved by security holders (1) 189,200 $28.10 165,100

Equity compensation plans not approved by security holders -- -- --

Total 189,200 $28.10 165,100 (1) This plan is the Amended and Restated Unit Option and Distribution Equivalent Plan of the Partnership. Director Recognition Program The General Partner has adopted the Director Recognition Program (the “Recognition Program”) that had been instituted by BMC in September 1997. The Recognition Program provides that, upon retirement or death and subject to certain conditions, directors receive a recognition benefit of up to three times their annual director’s fees (excluding attendance and committee fees) based upon their years of service as a member of the Board of Directors of the General Partner or BMC. A minimum of three full years of service as a member of the Board of Directors is required for eligibility under the Recognition Program. Members of the Board of Directors who are concurrently serving as an officer or employee of the General Partner or its affiliates are not eligible for the Recognition Program. No expenses were recorded under this program during 2002 and 2001. In 2000, expenses recorded under the program were $210,000. Mr. Hahl, who resigned from the Board of Directors in April 2001, was paid $75,000 under the Recognition Program at the time of his resignation. Item 12. Security Ownership of Certain Beneficial Owners and Management Services Company owns approximately 8.6 percent of the outstanding LP Units as of March 15, 2003. No other person or group is known to be the beneficial owner of more than 5 percent of the LP Units as of March 15, 2003. The following table sets forth certain information, as of March 15, 2003, concerning the beneficial ownership of LP Units by each director of the General Partner, the Chief Executive Officer of the General Partner, the four most highly compensated officers of the General Partner and by all directors and executive officers of the General Partner as a group. Such information is based on data furnished by the persons named. Based on information furnished to the General Partner by such persons, no director or executive officer of the General Partner owned beneficially, as of March 15, 2003, more than 1 percent of any class of equity securities of the Partnership or any of its subsidiaries outstanding at that date.

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Name Number of LP Units (1) Brian F. Billings ............................................................................................... 16,000 (2) Edward F. Kosnik............................................................................................. 14,000 (2) Joseph A. LaSala, Jr. 0 Alfred W. Martinelli......................................................................................... 9,000 (2) David J. Martinelli............................................................................................ 9,000 Stephen C. Muther............................................................................................ 25,600 Jonathan O’Herron ........................................................................................... 14,800 Steven C. Ramsey............................................................................................. 23,200 (3) William H. Shea, Jr. ......................................................................................... 20,200 (2) Frank S. Sowinski............................................................................................. 5,500 Ernest R. Varalli ............................................................................................... 13,500 (2) All directors and executive officers as a group (consisting of 11 persons) ...... 150,800 (1) Unless otherwise indicated, the persons named above have sole voting and investment power over the LP Units

reported. (2) The LP Units owned by the persons indicated have shared voting and investment power with their respective

spouses. (3) 3,200 of the LP Units have shared voting and investment power with his spouse.

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Item 13. Certain Relationships and Related Transactions The Partnership and the Operating Partnerships are managed by the General Partner pursuant to the Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), the several Amended and Restated Agreements of Limited Partnership of the Operating Partnerships (the “Operating Partnership Agreements”) and the several Management Agreements between the General Partner and the Operating Partnerships (the “Management Agreements”). BMC, which had been general partner of the Partnership, contributed its general partnership interest and certain other assets to the General Partner effective December 31, 1998. The General Partner is a wholly-owned subsidiary of BMC. Under the Partnership Agreement and the Operating Partnership Agreements, as well as the Management Agreements, the General Partner and certain related parties are entitled to reimbursement of all direct and indirect costs and expenses related to the business activities of the Partnership and the Operating Partnerships, except as otherwise provided by the Exchange Agreement (as discussed below). These costs and expenses include insurance fees, consulting fees, general and administrative costs, compensation and benefits payable to employees of the General Partner (other than certain executive officers), tax information and reporting costs, legal and audit fees and an allocable portion of overhead expenses. Such reimbursed amounts constitute a substantial portion of the revenues of the General Partner. Glenmoor owns all of the common stock of BMC. Glenmoor is owned by certain directors and members of senior management of the General Partner or trusts for the benefit of their families and certain director-level employees of Services Company. Glenmoor and BMC are entitled to receive an annual management fee for certain management functions they provide to the General Partner pursuant to a Management Agreement among Glenmoor, BMC and the General Partner. The disinterested directors of the General Partner approve the amount on a periodic basis. The management fee includes a Senior Administrative Charge of not less than $975,000 and reimbursement for certain costs and expenses. Amounts paid to Glenmoor and BMC in 2002 amounted to $1.9 million, including $975,000 for the Senior Administrative Charge and $0.9 million of reimbursed expenses. Amounts paid to Glenmoor and BMC in the years 2001 and 2000 for management fees equaled $2.0 million and $2.3 million, respectively, including $975,000 million for the Senior Administrative Charge in each year. The management fee also included $1.0 million and $1.3 million, respectively of reimbursed expenses in years 2001 and 2000. The General Partner receives incentive compensation payments from the Partnership pursuant to an incentive compensation agreement. In April 2001, the Partnership and the General Partner entered into the Second Amended and Restated Incentive Compensation Agreement (the “Incentive Compensation Agreement”). The Incentive Compensation Agreement provides that, subject to certain limitations and adjustments, if a quarterly cash distribution exceeds a target of $0.325 per LP Unit, the Partnership will pay the General Partner, in respect of each outstanding LP Unit, incentive compensation equal to (i) 15 percent of that portion of the distribution per LP Unit which exceeds the target quarterly amount of $0.325 but is not more than $0.35, plus (ii) 25 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.35 but is not more than $0.375, plus (iii) 30 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.375 but is not more than $0.40, plus (iv) 35 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.40 but is not more than $0.425, plus (v) 40 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.425 but is not more than $0.525, plus (vi) 45 percent of the amount, if any, by which the quarterly distribution per LP Unit exceeds $0.525. The General Partner is also entitled to incentive compensation, under a comparable formula, in respect of special cash distributions exceeding a target special distribution amount per LP Unit. The target special distribution amount generally means the amount which, together with all amounts distributed per LP Unit prior to the special distribution compounded quarterly at 13 percent per annum, would equal $10.00 (the initial public offering price of the LP Units split two-for-one) compounded quarterly at 13 percent per annum from the date of the closing of the initial public offering in December 1986. The principal change reflected in the Incentive Compensation Agreement was the elimination prospectively of a cap on aggregate incentive compensation payments to the General Partner effective December 31, 2005, or earlier if distributions on LP Units equal or exceed $.6375 per LP Unit for four consecutive quarterly periods ($2.55 annually). The amendments, which were designed to more closely align the interests of the General Partner and the Partnership, were approved by the Board of Directors

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of the General Partner based on a recommendation of a special committee of disinterested members of the Board. Incentive compensation paid by the Partnership for quarterly cash distributions totaled $10,838,000, $10,272,000 and $9,698,000 in 2002, 2001 and 2000, respectively. No special cash distributions have ever been paid by the Partnership. On January 23, 2003, the General Partner announced a quarterly distribution of $0.625 per GP and LP Unit payable on February 28, 2003, to the Unitholders of record on February 6, 2003. The Partnership paid the General Partner incentive compensation of $2.7 million as a result of this distribution. The following chart depicts the ownership relationships among the Partnership, the General Partner and various other parties:

CHART OF BUCKEYE-RELATED ORGANIZATIONS

Item 14. Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

The General Partner’s principal executive officer and its principal financial officer, after evaluating the effectiveness of the Partnership’s disclosure controls and procedures (as defined in Exchange Act Rules 13a – 14 and 15d – 14) as of a date within 90 days prior to the filing of this report (the “Evaluation Date”), have concluded that, as of the Evaluation Date, the Partnership’s disclosure controls and procedures were adequate

GLENMOOR, LTD.

100%

BUCKEYE MANAGEMENT COMPANY

(Delaware Corporation)

BUCKEYE PIPE LINE COMPANY

(Delaware Corporation)

100%

PUBLIC HOLDERS OF L.P. UNITS

BUCKEYE PARTNERS, L.P. (Delaware Limited Partnership)

90% L.P. Interest

Employee StockOwnership Plan

("ESOP")

BUCKEYE PIPE LINESERVICES COMPANY

(Employees)

100%

Services Agreement

9% L.P. Interest

1% G.P. Interest

99% L.P.Interest

1% G.P. Interest

BUCKEYE PIPE LINE HOLDINGS, L.P.

(Delaware Limited Partnership)

EVERGLADES PIPE LINE COMPANY L.P.

(Delaware Limited Partnership)

BUCKEYE PIPE LINE COMPANY, L.P.

(Delaware Limited Partnership)

LAUREL PIPE LINE COMPANY, L.P.

(Delaware Limited Partnership)

61

and effective to ensure that material information relating to the Partnership and its consolidate subsidiaries would be made known to them by others within those entities. (b) Changes in internal controls. There were no significant changes in the Partnership’s internal controls or in other factors that could significantly affect the Partnership’s disclosure controls and procedures subsequent to the date of their valuation, nor were there any significant deficiencies or material weaknesses in the Partnership’s internal controls. As a result, no corrective actions were required or undertaken.

PART IV

Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (Exhibits to be updated)

(a) The following documents are filed as a part of this Report:

(1) and (2) Financial Statements and Financial Statement Schedule—see Index to Financial Statements and Financial Statement Schedule appearing on page 28.

(3) Exhibits, including those incorporated by reference. The following is a list of exhibits filed as part of this Annual Report on Form 10-K. Where so indicated by footnote, exhibits which were previously filed are incorporated by reference. For exhibits incorporated by reference, the location of the exhibit in the previous filing is indicated in parentheses.

Exhibit Number (Referenced to

Item 601 of Regulation S-K)

3.1 — Amended and Restated Agreement of Limited Partnership of the Partnership, dated as ofApril 24, 2002. (1) (Exhibit 3.1)

3.2

— Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of thePartnership, dated as of April 26, 2002. (1) (Exhibit 3.2)

4.1 — Amended and Restated Indenture of Mortgage and Deed of Trust and Security Agreement, dated as of December 16, 1997, by Buckeye to PNC Bank, National Association, as Trustee.(5) (Exhibit 4.1)

4.2 — Note Agreement, dated as of December 16, 1997, between Buckeye and The PrudentialInsurance Company of America. (5) (Exhibit 4.2)

4.3 — Defeasance Trust Agreement, dated as of December 16, 1997, between and among PNC Bank,National Association, and Douglas A. Wilson, as Trustees. (5) (Exhibit 4.3)

4.4 — Certain instruments with respect to long-term debt of the Operating Partnerships which relate to debt that does not exceed 10 percent of the total assets of the Partnership and itsconsolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. §229.601. The Partnership hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.

10.1 — Amended and Restated Agreement of Limited Partnership of Buckeye, dated as ofMarch 25,2002. (1)(2) (Exhibit 10.1)

10.2 — Amended and Restated Management Agreement, dated October 4, 2001, between the General Partner and Buckeye. (1)(3) (Exhibit 10.2)

10.3 — Services Agreement, dated as of August 12, 1997, among the General Partner, the Manager and Services Company. (5) (Exhibit 10.9)

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10.4 — Amended and Restated Exchange Agreement, dated as of May 6, 2002, among the Partnership, the Operating Partnerships, the General Partner, Buckeye Management Company and Glenmoor Ltd. (5) (Exhibit 10.4)

10.5 — Acknowledgement and Agreement, dated as of May 6, 2002, between the Partnership and Glenmoor, Ltd. (1)

10.6 — Form of Executive Officer Severance Agreement. (5) (Exhibit 10.13)

10.7 — Form of Amendment No. 1 to Executive Officer Severance Agreement. (7) (Exhibit 10.18)

10.8 — Contribution, Assignment and Assumption Agreement, dated as of December 31, 1998,between Buckeye Management Company and Buckeye Pipe Line Company. (6) (Exhibit 10.14)

10.9 — Director Recognition Program of the General Partner. (4) (6) (Exhibit 10.15)

10.10 — Management Agreement, dated as of January 1, 1998, among BMC, the General Partner and Glenmoor. (9) (Exhibit 10.11)

10.11 — Amended and Restated Unit Option and Distribution Equivalent Plan of the Partnership, datedas of April 24, 2002. (1) (4) (Exhibit 10.12)

10.12 — Amended and Restated Unit Option Loan Program of Buckeye Pipe Line Company dated as of April 24, 2002. (1) (4) (Exhibit 10.13)

10.13 — Second Amended and Restated Incentive Compensation Agreement, dated April 22, 2001,between the General Partner and the Partnership. (8) (Exhibit 10.7)

10.14 — Credit Agreement, dated as of September 5, 2001, among the Partnership, SunTrust Bank andthe other signatories thereto. (9) (Exhibit 10.15)

10.15 — Credit Agreement, dated as of September 4, 2002, among the Partnership, SunTrust Bank andthe other signatories thereto.*

21.1 — List of subsidiaries of the Partnership.*

23.1 — Consent of Deloitte & Touche LLP.*

99.1 — Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

99.2 — Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

* filed herewith (1) Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P.

Quarterly Report on Form 10-Q for the quarter ended March 31, 2002. (2) The Amended and Restated Agreements of Limited Partnership of the other Operating Partnerships are not

filed because they are identical to Exhibit 10.1 except for the identity of the partnership. (3) The Management Agreements of the other Operating Partnerships are not filed because they are identical to

Exhibit 10.2 except for the identity of the partnership. (4) Represents management contract or compensatory plan or arrangement. (5) Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P.

Annual Report on Form 10-K for the year 1997.

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(6) Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P. Annual Report on Form 10-K for the year 1998.

(7) Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P.

Annual Report on Form 10-K for the year 1999. (8) Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P.

Quarterly Report on Form 10-Q for the quarter ended June 30, 2001. (9) Previously filed with the Securities and Exchange Commission as the Exhibit to the Buckeye Partners, L.P.

Annual Report on Form 10-K for the year 2001. (b) Reports on Form 8-K during the quarter ended December 31, 2002. (1) On October 3, 2002, the Partnership filed a current report on Form 8-K announcing its proposed purchase of an approximate 18 percent interest in Colonial Pipeline Company. (2) On October 15, 2002, the Partnership filed a current report on Form 8-K amending the financial statements included in its annual report on Form 10-K for the year ended December 31, 2001 filed with the Commission on March 28, 2002. The purpose of the amendment was to add an additional Note 24 to the financial statements. Note 24 contains certain pro forma results for the years ended December 31, 2001, 2000 and 1999, as if the non-amortization provisions of Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," which the Registrant adopted on January 1, 2002, had been applied. These pro forma results were not required to be included in the Registrant's financial statements at the time the original Form 10-K was filed. (3) On November 1, 2002, the Partnership filed a current report on Form 8-K announcing the termination of its proposed purchase of an approximate 18 percent interest in Colonial Pipeline Company.

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SIGNATURES

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

BUCKEYE PARTNERS, L.P. (Registrant) By: Buckeye Pipe Line Company, as General Partner Dated: March 24, 2003 By: /s/ WILLIAM H. SHEA, JR. William H. Shea, Jr. (Principal Executive Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Dated: March 24, 2003 By: /s/ BRIAN F. BILLINGS Brian F. Billings Director Dated: March 24, 2003 By: /s/ EDWARD F. KOSNIK Edward F. Kosnik Director Dated: March 24, 2003 By: /s/ JOSEPH A. LASALA, JR. Joseph A. LaSala, Jr. Director Dated: March 24, 2003 By: /s/ ALFRED W. MARTINELLI Alfred W. Martinelli Chairman of the Board and Director Dated: March 24, 2003 By: /s/ DAVID J. MARTINELLI David J. Martinelli Director Dated: March 24, 2003 By: /s/ JONATHAN O’HERRON Jonathan O’Herron Director Dated: March 24, 2003 By: /s/ STEVEN C. RAMSEY Steven C. Ramsey (Principal Financial Officer and Principal Accounting Officer) Dated: March 24, 2003 By: /s/ WILLIAM H. SHEA, JR. William H. Shea, Jr. Director Dated: March 24, 2003 By: /s/ FRANK S. SOWINSKI Frank S. Sowinski Director Dated: March 24, 2003 By: /s/ ERNEST R. VARALLI Ernest R Varalli Director

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CERTIFICATIONS

I, William H. Shea, Jr. certify that:

1. I have reviewed this annual report on Form 10-K of Buckeye Partners, L.P.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or

omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual

report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure

controls and procedures (as defined in Exchange Act Rules 13a–14 and 15d–14) for the registrant and we have:

a. designed such disclosure controls and procedures to ensure that material information relating to

the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b. evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date

within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and c. presented in this annual report our conclusions about the effectiveness of the disclosure controls

and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors:

a. all significant deficiencies in the design or operation of internal controls which could adversely

affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b. any fraud, whether or not material, that involves management or other employees who have a

significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 24, 2003 /s/ William H. Shea, Jr. William H. Shea, Jr. President and Chief Executive Officer Buckeye Pipe Line Company as General Partner of Buckeye Partners, L.P.

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I, Steven C. Ramsey certify that:

1. I have reviewed this annual report on Form 10-K of Buckeye Partners, L.P.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or

omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual

report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure

controls and procedures (as defined in Exchange Act Rules 13a–14 and 15d–14) for the registrant and we have:

a. designed such disclosure controls and procedures to ensure that material information relating to

the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b. evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date

within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c. presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the

registrant’s auditors and the audit committee of registrant’s board of directors.

a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b. any fraud, whether or not material, that involves management or other employees who have a

significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 24, 2003 /s/ Steven C. Ramsey Steven C. Ramsey Senior Vice President, Finance and Chief Financial Officer Buckeye Pipe Line Company as General Partner of Buckeye Partners, L.P.

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INDEPENDENT AUDITORS’ REPORT

To the Partners of Buckeye Partners, L.P.: We have audited the consolidated financial statements of Buckeye Partners, L.P. and its subsidiaries (the “Partnership”) as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, and have issued our report thereon dated March 19, 2003, which expresses an unqualified opinion and includes an explanatory paragraph as to the Partnership’s change in methods of accounting for goodwill and other intangible assets to conform to Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”, effective January 1, 2002; such report is included elsewhere in this Form 10-K. Our audits also included the condensed financial information (Parent Only) of Buckeye Partners, L.P. listed in Item 15. This condensed financial information is the responsibility of the Partnership’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such condensed financial information, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP Philadelphia, Pennsylvania March 19, 2003

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SCHEDULE I BUCKEYE PARTNERS, L.P.

Registrant’s Condensed Financial Information (Parent Only) (In thousands)

BALANCE SHEETS December 31, 2002 2001

Assets Current assets Cash and cash equivalents........................................................................................ $ 28 $ 26 Other current assets .................................................................................................. 157,788 131,066 Total current assets........................................................................................... 157,816 131,092 Other non-current assets........................................................................................... 1,045 1,252 Investments in and advances to subsidiaries (at equity) ........................................... 365,538 354,882 Total assets ....................................................................................................... $ 524,399 $ 487,226 Liabilities and partners’ capital Current liabilities.............................................................................................................. $ 1,967 $ 1,330 Long-term debt................................................................................................................. 165,000 133,000 Partners’ capital General Partner......................................................................................................... 2,870 2,834 Limited Partners ....................................................................................................... 355,475 351,057 Receivable from exercise of options ........................................................................ (913) (995) Total partners’ capital....................................................................................... 357,432 352,896 Total liabilities and partners’ capital ................................................................ $ 524,399 $ 487,226

STATEMENTS OF INCOME

Year Ended December 31, 2002 2001 2000

Equity in income of subsidiaries ...................................................................... $ 89,001 $ 80,973 $106,087 Operating expenses........................................................................................... (432) 293 (59) Investment income ........................................................................................... 4 - 1 Interest and debt expense.................................................................................. (5,833) (1,592) - Incentive compensation to General Partner ...................................................... (10,838) (10,272) (9,698) Net income................................................................................ $ 71,902 $ 69,402 $ 96,331

STATEMENTS OF CASH FLOWS Year Ended December 31, 2002 2001 2000

Cash flows from operating activities: Net income................................................................................................ $ 71,902 $ 69,402 $ 96,331 Adjustments to reconcile net income to net cash provided by operating activities:

Increase in investment in subsidiaries............................................... (10,656) (6,181) (31,584) Change in assets and liabilities: Other current assets................................................................... (26,722) (130,046) (885) Current liabilities ...................................................................... 637 918 (22) Other non-current assets ........................................................... 207 87 - Net cash (used by) provided by operating activities................ 35,368 (65,820) 63,840 Cash flows from financing activities: Proceeds from exercise of unit options ..................................................... 566 576 1,013 Debt issuance costs ................................................................................... - (1,339) - Proceeds from issuance of long-term debt ................................................ 32,000 133,000 - Distributions to Unitholders...................................................................... (67,932) (66,464) (64,951) Net (decrease) increase in cash and cash equivalents ............................ 2 (47) (98) Cash and cash equivalents at beginning of period .................................... 26 73 171 Cash and cash equivalents at end of period .............................................. $ 28 $ 26 $ 73 See footnotes to consolidated financial statements of Buckeye Partners, L.P.